ferreiradoneivanfernandes - tese.pdf

UNICAIVIP

Numero: 292

UNIVERSIDADE ESTADUAL DE CAMPINAS

INSTITUTO DE GEOCIENCIAS

P6s-Gradua.;iio em Geociencias

Area de Administra.;iio e Politica de Recursos Minerais

DONEIV AN FERNANDES FERREIRA

A.t"'TICIPATING IMPACTS OF FINANCIAL ASSURANCE REQUIREMENTS FOR

OFFSHORE DECOMMISSIONING: A DECISION MODEL FOR THE OIL INDUSTRY

Tese apresentada ao Instituto de Geociencias como parte

dos requisitos para obtenviio do titulo de Doutor em

Ciencias.

Orientador: Prof. Dr. Saul B. Suslick

CAMPINAS- SAO PAULO

JULHO 2003

iUNICAMP BfBLIOTECA CENTRAl

r"B'. ' OJ! • l CE CU!

V EX -:::.-:r<rr TOMBO BCi 5 GJ(}9 PROC . .J 6- ./::) -'f /0 3

PRECO $/J..f, ~d c~ o[l]

DATA 110/0:3 N' CPD

Ferreira, Doneivan Fernandes F413a Anticipating impacts of financial assurance requirements for offshores

decommissioning: a decision model for the oil industry I Doneivan Fernandes Ferreira.- Campinas,SP.: [s.n.], 2003.

Orientador: Saul Barisnik Suslick Tese ( doutorado) Universidade Estadual de Campinas, Instituto de

Geociencias.

I. Industria petrolifera. 2. Processos decis6rios- Modelos Matem;iticos. 3. Recursos Naturais. 4. Abandono (Direito Maritimo). I. Suslick, Saul Barisnik IT. Universidade Estadual de Campinas, Instituto de Geociencias ill. Titulo.

ii



UN I CAMP POS-GRADUA<;:AO EM GEOCIENCIAS

AREA DE ADMINISTRA<;:AO E POLITICA DE RECURSOS

MINERAlS

AUTOR: DONEIV AN FERNANDES FERREIRA

ORIENTADOR: Prof. Dr. Saul B. Suslick

Aprovada em: 0 ll I _j_; Q ~:;5

PRESIDENTE: Prof. Dr. Saul B. Suslick ---------

EXAMINADORES:

Prof. Dr. Saul B. Suslick

Prof. Dr. Denis J. Schiozer

Prof. Dr. Celso K. Morooka

Prof. Dr. Alberto S. de Almeida

Prof. Dr. Edmilson M. Santos

Campinas, 04 de julho de 2003

iii

UNICAMII=I

STATE UNIVERSITY OF CAMPINAS

INSTITUTE OF GEOSCIENCES

DEPARTMENT OF GEOLOGY AND NATURAL RESOURCES

AREA OF MINERAL RESOURCES POLICY AND

MANAGEMENT

AUTHOR: DONEIV AN FERNANDES FERREIRA

Advisory Committee:

Prof. Dr. Saul B. Suslick

Prof. Dr. Denis J. Schiozer

Prof. Dr. Celso K. Morooka

Prof. Dr. Alberto S. de Almeida

Prof. Dr. Edmilson M. Santos

Dissertation submitted to the Institute of Geosciences of the State University of Campinas in partial fulfillment of the requirements for the degree of Doctor of Sciences 2003

Campinas, July 04, 2003

v

DEDICATORY

in memoriam

My mother died when I was just beginning this thesis project. I was able to spend the last

month of her life at her bedside along with my family. This work is dedicated to the "living

with-purpose" spirit manifested in the life of my mother, Doriza Fernandes Ferreira.

vii

UNICAMP BUOTECA CENTRAL

SE~Ao Cl E

ACKNOWLEDGMENTS

Firstly and most importantly, thanks to God, because He is Good.

Ju and Viv, my girls, your constant encouragement was the essential factor when the

burdens of writing seemed undefeatable. My best friend and precious wife Ju, who has

wholeheartedly supported my commitment of time and attention to this project. I could never

make it without your love, patience, understanding, and unfaltering encouragement. I thank God

for making our love such a great treasure. My little Viv, you cannot begin to imagine how much

playing with you every day helped me finish this thesis. I will always cherish these moments.

Girls, I love you.

To my parents Dr. Darny Ferreira and Doriza Fernandes Ferreira (in memoriam) who

taught me the way I should walk. You nourished my life, provided me with some greatly needed

correction, motivated my curiosity, challenged my thinking, fired my heart, and blessed my soul.

Thanks for leaving such good footprints to be followed. To my brother Dr. Davis Fernandes

Ferreira, I am so very grateful for your friendship and unrelenting care. Bro, live long and

prosper! To my sisters, Dale! F. Medina and Dorine Ferreira, and respective families, thanks for

opening your homes and your hearts for my family during my fellowship in the States.

I am especially grateful to Professor Dr. Saul B. Suslick, my adviser. Thanks for your

guidance, patience, and care, but most importantly, thanks for believing in me. I am also thankful

to Dr. Aroldo Misi for the encouragement and direction during my pre-UNICAM stage.

Support for this research project was provided by the State University of Carnpinas

(lJ1',1CAMP) and the Foundation for the Coordination of Higher Education and Graduate

Training (CAPES). Thanks to the Brazilian Petroleum Agency (ANP) and Center for Petroleum

Studies (CEPETRO), for project opportunities. Thanks to the Institute for Ecological Economics

(IEE) and University of Maryland (UMD), for having me as a fellow for 18 month.

Special thanks to state regulators, and decommissioning and bonding specialists who took

the time to provide me with important information and insightful discussions. Thanks to Dr.

Robert Costanza, Director of the IEE, for the learning opportunity and to Dr. Roe! Baums for the

modeling coaching. I am deeply indebted to Dr. Joshua Farley and the Farley family for being

our family in Maryland.

ix

Thanks to Paula Moura for the invaluable help with programming and in the Petrobond

Project. To my colleagues at the LAGEIUNICAMP, thank you for numerous intelligent

discussions. I am also thankful to Valdirene Pinotti and Maria Helena S. Ricardo, for the much

needed help and for being so sweet and caring, and to Marcia A. Schenfel Baena, for the helpful

comments in the manuscript.

A special thanks to my in-laws, Joao Benjamim and !racy Pinheiro, for being near when I

needed. Thanks to Dr. Mariano Leone! de Souza, Leila de Souza and the entire Souza Family,

for being like family.

X

EPIGRAPH

Lord, thou hast been our dwelling place in all generations. Before the mountains were brought

forth, or ever thou hadst formed the earth and the world, even from everlasting to everlasting,

thou art God. Thou turnest man to destruction; and sayest, Return, ye children of men. For a

thousand years in thy sight are but as yesterday when it is past, and as a watch in the night.

Thou carriest them away as with a flood; they are as a sleep: in the morning they are like grass

which groweth up. In the morning it flourisheth, and groweth up; in the evening it is cut down,

and withereth. For we are consumed by thine anger, and by thy wrath are we troubled. Thou

hast set our iniquities before thee, our secret sins in the light of thy countenance. For all our

days are passed away in thy wrath: we spend our years as a tale that is told. The days of our

years are threescore years and ten; and if by reason of strength they be fourscore years, yet is

their strength labour and sorrow; for it is soon cut off, and we fly away. Who knoweth the power

of thine anger? even according to thy fear, so is thy wrath. So teach us to number our days, that

we may apply our hearts unto wisdom. Return, 0 LORD, how long? and let it repent thee

concerning thy servants. 0 satisfy us early with thy mercy; that we may rejoice and be glad all

our days. Make us glad according to the days wherein thou hast ajjlicted us, and the years

wherein we have seen evil. Let thy work appear unto thy servants, and thy glory unto their

children. And let the beauty of the LORD our God be upon us: and establish thou the work of

our hands upon us; yea, the work of our hands establish thou it.

(Moses, Hebrew Lawgiver, 13th cent. B. C.)

"I do not feel obliged to believe that the same God who has endowed us with sense, reason, and

intellect has intended us to forgo their use. "

(Galileo Galilei, Italian Astronomer and Physicist, 1564-1642)

xi

INDEX Dedicatory Acknowledgements Epigraph List of Tables List of Figures Abbreviations Abstract Resumo Estendido (in Portuguese) CHAPTER I- INTRODUCTION

1.1. Overview 1.2. Purpose and Justification 1.3. Methodology and Study Outline 1.4. Literature Revision

CHAPTER II - MAIN CONCEPTS

Article I

2.1. 2.2. 2.3. 2.4. 2.5. 2.6.

CHAPTER III-3.1. 3.2. 3.3. 3.4. 3.5. 3.6. 3.7. 3.8. 3.9.

3.10. 3.11. 3.12. 3.13.

CHAPTERN-4.1. 4.2. 4.3. 4.4. 4.5. 4.6. 4.7.

A Decision Model for Financial Assurance Instruments in the Upstream Petroleum Sector Introduction Forms of Environmental Damage Financial Assurance Systems and Instruments Decision Model Results and Discussion Conclusions DECOMMISSIONING End-of-Leasing Obligations and Platform Decommissioning The Development of the Legal Framework Historical Overview Decommissioning of Offshore Installations Decommissioning Options The US Rigs-to-Reef Program Environmental, Health and Safety Considerations Technological Considerations Economic Considerations Decommissioning Costs Cost Drivers in Decommissioning Suggestion For Decommissioning Cost Assessment Decommissioning Discussion FINANCIAL ASSURANCE MECHANISMS- BONDS Environmental Costs Regulatory Approaches: Command and Control vs. Economic Incentive The Bonding System in the Oil Industry Bonding Cost Setting Bond Amount and Duration Forfeiture and Bond Release The Bonding System Step-by-Step

xiii

v VI

vm IX

X

xu XIV

XVI

1 I 3 5 8

10

II

12 13 17 25 32 33 34 34 38 46 48 50 64 67 70 72 76 82 85 89 92 92 94 97

100 101 104 105

4.8. 4.9.

4.10.

4.11.

4.12.

4.13.

4.14. 4.15.

CHAPTERV-5.1. 5.2.

CHAPTERVl-

Article II

6.1. 6.2. 6.3. 6.4. 6.5. 6.6.

Article III

6.7. 6.8. 6.9.

6.10. 6.11. 6.12. 6.13.

CHAPTER Vll REFERENCES APPENDIX A APPENDIXB APPENDIXC

APPENDIXD

Different Forms of Bonding Instruments Financial Assurance Systems The Financial Assurance System in the US Coal Mining Industry (OSMRE) Bonding System for the US Offshore Oil and Gas Decommissioning Program (US MMS) The Financial Assurance System in the US Hardrock Mining Industry (Us Bureau of Land Management) The Financial Assurance System in the US Onshore Oil Industry (US BLM) Comparative Analysis of the Four U.S. Bonding Systems Regulatory Issues: Discussion FISCAL TREATMENT- DECOMMISSIONING & BONDS Decommissioning Fiscal Treatment - Discussion Bond Fiscal Treatment- Discussion DECISION TOOLS: ECONOMIC MODELS An Exploratory Analysis of the Environmental Bonding System for Upstream Petroleum Projects Introduction Bonding Systems Methods Analysis Results and Discussion Conclusions IdentifYing Potential Impacts of Bonding Instruments on Offshore Oil Projects Introduction Offshore Industry and Decommissioning The Bonding System Financial Evaluation of Bonding Options for Three Producing Oil Fields Results Regulatory Issues and Bonding Systems Conclusions CONCLUSIONS

BOND EVALUATION QUESTIONNAIRE DECOMMISSIONING OF OFFSHORE INSTALLATIONS PETROBOND- AN ALGORITHM TO ANTICIPATE ECONOMIC IMPACTS OF BONDING INSTRUMENTS STELLA MODELING TOOL: DECOMMISSIONING AND BONDING SCENARIOS

xiv

110 132

132

142

154

155

157 160 164 164 167 169

169

170 170 172 180 181 188

191

191 192 193 196 202 204 208 209 216 237 238

241

245

LIST OF TABLES

CHAPTER II. MAIN CONCEPTS

TABLE 2.1. Main stakeholders TABLE 2.2. Instrument options TABLE 2.4. Instruments and proposed classification TABLE 2.5. Attributes/criteria TABLE 2.6. Matrix xij: performance of bonding alternatives on attributes TABLE 2.7. Total utility

CHAPTER III. DECOMMISSIONING

TABLE 3.1. Cost comparison: refurbished vs. New TABLE 3.2. Case history- el300 a- GOM TABLE 3.3. Risk assessment based on probability of occurrence and consequences TABLE 3.4. . Selected disposal route TABLE 3.5. Rigs-to-reef opportunity to reduce costs in California TABLE 3.6. Joint industry approach to reduce costs in California TABLE 3.7. Decommissioning costs by region, category and installation type TABLE 3.8. North Atlantic Platforms . TABLE 3.9. Platforms in the Mediterranean Sea Region TABLE 3.10. West Africa offshore inatallations TABLE 3.11. Brazilian offshore platforms TABLE 3.12. Assessment of proposed options for Brent Spar TABLE 3.13. Cost estimates for disposal of pipelines in Norway TABLE 3.14. US MMS decommissioning estimates for offshore California TABLE 3.15. Comparative cost analysis: offshore California & southern north sea TABLE 3.16. General chronograrn for onshore closure- the phased approach

CHAPTER IV. BONDS

TABLE4.1. TABLE 4.2. TABLE4.3. TABLE4.4. TABLE4.5.

US bond requirements for onshore projects Commutation account balance- finite insurance Commutation account balance- finite inaurance MMS estimated ex-post costs according to water depth Subjective comparative analysis of studied bonding systems

CHAPTER VI. MODELS

TABLE 6.1. Project parameters TABLE 6.2. Bond parameters TABLE 6.3. Fiscal calculations TABLE 6.4. Project information summary TABLE 6.5. Model for LSAA bond annual payments TABLE 6.6. Sensitivity analysis for fields A, Band C, and bond options TABLE 6.7. Qualitative evaluation ofbonds using the simulation model

APPENDIX A. BOND EVALUATION QUESTIONNAIRE

TABLE A.l. Questionnaire APPENDIX B. OFFSHORE DECOMMISSIONING TABLE B.1. Nonexclusive reuse matrix suggestion TABLE B.2. Decommissioning cost estimate form APPENDIX C. PETROBOND VARIABLES TABLEC.l. TABLEC.2. TABLEC.3.

Operational variables Financial variables Bond-related variables

XV

22 25 28 30 31 32

59 60 62 62 65 72 77 78 78 79 80 81 84 85 87 89

102 127 127 150 159

177 178 179 199 202 203 205

237

238 239

241 242 244

LIST OF FIGURES

CHAPTER I. INTRODUCTION

FIGURE 1.1. World Platform Population FIGURE 1.2. Thesis Flowchart FIGURE 1.3. Methodology

CHAPTER II. MAIN CONCEPTS

FIGURE 2.1. Environmental Damage Categories. FIGURE 2.2. Marginal costs and benefits of decommissioning operations. FIGURE 2.3. The dynamics of the bonding cycle. FIGURE 2.4. Map Level Diagram for the Stella Model.

CHAPTER III. DECOMMISSIONING

FIGURE 3.1. Main International and Regional regulations, treats and guidelines. FIGURE 3.2. Brent Spar and the stained Shell's logo. FIGURE 3.3. North Sea Decommissioning Timetable. FIGURE 3.4. Platform types. FIGURE 3.5. Norwegian Troll A platform. FIGURE 3.6. Sinking Brazilian P-36 SS Platform. FIGURE 3.7. GOM average platform installations and removals from 1987 to 1999. FIGURE 3.8. GOM's present and future decommissions FIGURE 3.9. GOM decommissioning cost per ton. FIGURE 3.10. Decommissioning options and endpoints for topsides and substroctures. FIGURE 3.11. Variants for removal and disposal alternatives for different stroctures and needs. FIGURE 3.12. Comparative scale indicating the size of small and large stroctures. FIGURE 3.13. Environmental character of the reutilization principle. FIGURE 3.14. Reuse timing adjnstroent. FIGURE 3.15. Sea Launch Lift. FIGURE 3.16. Islands of Life. FIGURE 3.17. Platformless Field Development FIGURE 3.18. Schematics of the Phillips. FIGURE 3.19. GOM Historical Decommissioning Cost. FIGURE 3.20. Decommissioning Study Execution Flowchart. FIGURE 3.21. Environmental character of the proposed 5 R's Approach. FIGURE 3.22. Pre-project decommissioning planning for stringent regimes.

CHAPTER IV. BONDS FIGURE 4.1. Cost Categories and deggree of difficulty. FIGURE 4.2. Examples of environmental costs. FIGURE 4.3. Ket Stakeholders involved in the bonding process. FIGURE 4.4. Provisions for premature and unplunned decommissioning operations. FIGURE 4.5. The Bond Effect FIGURE 4.6. Risk Assessment Model. FIGURE 4.7. Risk Assessment Matrix.

FIGURE4.8.

FIGURE4.9.

Finite Insurance strocture compared to traditional environmental insurance policies, and different methods of funding finite insurance. MMS Bonding System Schematics.

xvii

1 5 7

15 19 27 29

39 47 47 51 51 51 53 53 54 54 55 57 57 63 63 65 73 73 79 86 91 91

93 97 99

101 107 109 Ill

129

143

CHAPTER V. FISCAL TREATMENT

FIGURE 5.1. Generic fiscal system including bonding system.

CHAPTER V. MODELS

FIGURE6.1. FIGURE6.2. FIGURE6.3. FIGURE6.4. FIGURE6.5. FIGURE6.6. FIGURE6.7. FIGURE6.8. FIGURE6.9. FIGURE 6.10.

Macro-structure for the Petrobond Algorithm. Diagram for the exploration phase. Diagram for the Closure and Post-Closure phases. Comparison diagram indicating taxes and other government contributions. Total participations against total gross revenue (100"/o) for Field C (148 MMbbl). NPV vs. Closure Costs. GT vs. Closure Costs Hypothetical bond system. Scheme showing the path for the establishment of the bond value Graphic Representation of costs and taxes using the project simulation modeL

CHAPTER VI. CONCLUSIONS

FIGURE 7.1. FIGURE 7.2.

APPENDIXC

FIGUREC.l.

APPENDIXD

FIGURED.!. FIGURED.2. FIGURED.3. FIGURED.5.

Summary of risks for the regulatory agency Summary of regulatory cost causing agents

Petrobond Computational Algorithm

Interface Level - Concepts Interface Level - Input Window Map Level - Decommissioning Submodel Carbon Model - Map Level

xviii

167

173 174 175 181 183 187 189 197 198 200

211 211

243

245 245 249 251

AMD

A-1\!P

AP BIA BLM BOE BSAB CB CCA CCCP CD CEPETRO CGB CPLAL CSB CVBS DOCD DOl DPP DTI ECA EIA EIP EP EPA ESF FIPB FPSO

FRCB FUN CAMP FWS G&G GOM HLV ICMS IGP IGS IMO IPB

ISO

JACK-UP LCCB LOC LSAA LSCA MMS na NGO NIN NIOZ NORMS NPD

ABBREVIATIONS

ACID MINE DRAINAGE BRAZILIAN NATIONAL PETROLEUM AGENCY (AGENCIA NACIONAL DO PETRO LEO) ANNUITY POLICIES BUREAU OF INDIA_"/ AFFAIRS BUREAU OF LAND MANAGEMENT BARREL OF OIL EQUN ALENTS BUDGET SET-ASIDE BONDS COLLATERAL BOJ:\1)S CASH COLLATERAL ACCOUNTS CLEANUP COST CAP POLICY CERTIFICATES OF DEPOSIT CENTER FOR PETROLEUM STUDIES (UNICAMP) CORPORATE GUARANTEE BOND CUMULATIVE POTENTIAL LEASE ABANDONMENT LIABILITIES CORPORATE SURETY BONDS CONTROLLED VARIABLE BUOYANCY SYSTEM DEVELOPMENT OPERATION COORDINATION DOCUMENT U.S. DEPARTMENT OF THE INTERIOR DEVELOPMENT AND PRODUCTION PLAN U.K. DEPARTMENT OF TRADE AND INDUSTRY ESCROW COLLATERAL ACCOUNTS ENVIRONMENTAL IMPACT ASSESSMENT REPORT ENVIRONMENTAL INSURANCE POLICY EXPLORATION PLA-"1 UNTTED STATES ENVIRONMENTAL PROTECTION AGENCY EXTERNAL SINKING FUNDS FINITE INSURANCE POLICY FLOATING PRODUCTION SYSTEM AND OFFLOADING FUTURE REVEJ:\'UE COMMITMENTS BONDS UNICAMP FOUNDATION (STATE UNIVERSITY OF CAMPINAS) U.S. FISH AND WILDLIFE SERVICE GEOLOGICAL AND GEOPHYSICAL GULF OF MEXICO HEAVY LIFT VESSEL INTERNATIONAL COUNCIL ON METALS AND THE ENVIRONMENT INSURANCE-GUARA_"'TEE POLICY INVESTMENT GRADE SECURITY INTERNATIONAL MARITIME ORGA.t"'IZATION INSURA."'CE POLICY B0l\1)S INTERNATIONAL CONSENSUS STANDARD (INTERNATIONAL ORGANIZATION FOR STANDARDIZATION) STEEL GRAVITY STRUCTURE LINE OF CREDIT COLLATERAL BOND LETTER OF CREDIT LEASING SPECIFIC ABANDONMENT ACCOUNTS LEASING SPECIFIC COLLATERAL ACCOUNTS MINERALS MA_"'AGEMENT SERVICE NOT AVAILABLE I NOT APPLICABLE NON-GOVERNMENTAL ORGANIZATIONS NOTICES OF INCIDENTS OF NONCOMPLIANCE DUTCH INSTITUTE FOR MARINE RESEARCH NATURAL-OCCURRING RADIOACTIVE MATERIAL NORWEGIAN PETROLEUM DIRECTORATE

xix

NPS NPV NS 1'\'WF oc ocs ODCP

OSCOM

OSM

OSPAR

P-BONDS PPCA ppp RECB Rl'VIP ROW RRR RRRRR RTR SAA S-BONDS S-FUNDS SMCRA SRCB SSP T-BOND TLP TPB TPWD UKOOA UN UNCLOS UNEP UNICAMP USGS

NATIONAL PARK SERVICE NET PRESENT VALUE NORTH SEA NATIONAL WILDLIFE FUND OFFSHORE CALIFORNIA OUTER CONTINENTAL SHELF OFFSHORE DECOMMISSIONING COMMUNICATIONS PROJECT OSLO COMMISSION GUIDELINES FOR THE DISPOSAL OF INSTALLATIONS AT SEA OFFICE OF SURFACE MINING RECLAMATION AND ENFORCEMENT CONVENTION FOR THE PROTECTION OF THE MARINE ENVIRONMENT IN THE NORTHEAST ATLANTIC POOLBo:t-.'DS PAID-IN COLLATERAL ACCOUNTS OR PRE-PAID COLLATERAL ACCOUNTS POLLUTERS PAY PRINCIPLE REAL ESTATE COLLATERAL BOND ROYALTY MANAGEMENT PROGRAM PIPELINE RIGHT-OF-WAY (3R' s) REDUCE, REUSE, AND RECYCLE (5R's) REDUCE, REENGINEER, REUSE, RIGS-TO-REEF, AND RECYCLE. RIGS-TO-REEF PROGRAM SURETY ASSOCJATION OF AMERICA SELF BOJ\'DS STATE FUNDS SURFACE MINING CONTROL AND RECLAMATION ACT SALVAGE REVENUE COLLATERAL BOND SEMI-SUBMERSIBLE PLATFORM TREASURY BONDS TENSION LEG PLATFORM THIRD-PARTY BONDS TEXAS PARKS Al\'D WILDLIFE DEPARTMENT UNITED KINGDOM OFFSHORE OPERATORS ASSOCJATION UNITED NATIONS Ul\1TED NATIONS CONVENTION ON THE LAW OF THE SEA UNITED NATIONS ENERGY PROGRAMME STATE UNIVERSITY OF CAMPINAS U.S. GEOLOGICAL SURVEY

XX

UNICAMP

STATE UNIVERSITY OF CAMPINAS/

INSTITUTE OF GEOSCIENCES

DOCTORAL DEGREE IN GEOSCIENCES

AREA OF MINERAL RESOURCES POLICY AND

MANAGEMENT

ANTICIPATL~G IMPACTS OF FINANCIAL ASSURANCE REQUIREMENTS FOR

OFFSHORE DECOMMISSIONING: A DECISION MODEL FOR THE OIL INDUSTRY

ABSTRACT

DOCTORATE THESIS

Doneivan Fernandes Ferreira

The present thesis describes the financial assurance system (bonding system), an innovative incentive approach being adopted by several countries in different productive areas, with the objective of guaranteeing the availability of funds for the compliance of all ex -post environmental obligations in the offshore petroleum industry. This work provides a general assessment of several decommissioning-related issues that economically impact offshore petroleum projects around the world. There are several forms of bonding instruments currently available providing significant flexibility for companies to meet end-of-leasing requirements. Bonds will provide advantages such as: (!) ensure satisfactory regulatory compliance; (2) safeguard government and taxpayers by attaining reasonable protection from default at a minimum increase in project costs; and (3) protect the environment from potential harm resulting from failure to carryout proper ex-post operations in a timely fashion. Based upon a discount cash flow analysis this study uses an experimental approach, suggesting interactive decision models (simulation models) estimating costs, and identifying the instrument option which offers the least economic impact in the project and, at same time, provides the best financial guarantee for all stakeholders involved in the process. Simulations confirm the current scenario where regulators are likely to require surety bonds, letters of credit, and periodic payment collateral account tools. Sensitivity analysis of Net Present Value and Government Take value indicate expost insurance policies, sureties, and letters of credit may cause fewer impacts yielding significantly better payoffs. Simulations confirm that small projects can be severely affected when collateral account instruments are used.

xxi



POS-GRADUA<;:Ao EM GEOCIENCIAS

AREA DE ADMINISTRA<;:AO E POLITICA DE RECURSOS MINERAlS

TESE DE DOUTORADO

TEMA: ANTECIPA.~DO IMPACTOS DE OBRIGA<;:OES DE GARANTIA

FINANCEIRA PARA DESCOMISSIONAMENTO DE INSTALA<;:OES MARiTIMAS:

UM MODELO DECISORIO PARA A INDUSTRIA DO PETROLEO

RESUMO ESTENDIDO

Ha algum tempo o setor de petr61eo foi obrigado a se preocupar com aspectos ambientais

e de seguranya das areas onde mantinham atividades. Para garantir que tais areas fossem

devolvidas a sociedade em condiyoes de sustentabilidade, os 6rgaos reguladores comeyaram

exigir a realizayao de algumas operayoes especificas, visando aspectos arnbientais e de

seguranya. Este processo tern sido denominado "fase de abandono".

Desde entao, a preocupayao passou a ser com o risco de descumprimento de tais

obrigayoes, ja que se estas nao fossem cumpridas, a responsabilidade seria naturalmente

transferida para o 6rgao regulador. 0 sistema de garantia fmanceira comeyou, entao, a ser

aplicado no setor como uma forma de gerar incentivos financeiros e garantir recursos para o

cumprimento de tais obrigayoes mesmo em caso de abandono prematuro, insolvencia ou

negligencia.

Nos ultimos anos, com a exaustao econ6mica de inumeros reservat6rios de oleo e gas e

com o persistente aumento da demanda mundial por combustiveis f6sseis, iniciou-se urn processo

de disponibilizayao e oferta de campos marginais no cenano intemacional e nacional. Esta oferta

deve-se tarnbem ao desinteresse das grandes companhias em aplicar recursos em projetos deste

tipo, onde o lucro geralmente e marginal ou inexistente. No entanto, concessionanas pequenas e

independentes sao capazes de produzir com custos operacionais significativamente mais baixos,

viabilizando lucros satisfat6rios, a depender das condiyoes do mercado.

xxiii

Com a abertura do setor de petr6leo e gas natural no Brasil, aumentou o interesse por

oportunidades no pais. Apesar da preocupayao em fornecer urn cenfuio atrativo para novos

investimentos, a Agencia Nacional do Petr6leo (ANP) e demais 6rgao ambientais sao tambem

responsaveis pela garantia de que as concessoes sejam retornadas em condiyoes de auto

sustentabilidade ambiental e sem oferecer riscos de seguranya.

Dentro deste cenfuio, o 6rgao regulador enfrenta alguns graves problemas: (1) grandes

concessionfuias iniciam urn processo de oferta de campos marginais negligenciando a

responsabilidade de verificar a capacitayao dos candidatos em cumprir as obrigayoes de final de

contrato; (2) algumas empresas podem ser tentadas a formar companhias espUrias visando a

exonerayao de suas responsabilidades ambientais futuras; (3) flutuayoes no mercado afetam

significativamente companhias pequenas e independentes que operam campos margma1s,

aumentando o risco de insolvencia; (4) pequenos operadores, alem de financeiramente

vulneraveis, muitas vezes nao possuem a experiencia necessaria para lidar com problemas

ambientais, aumentando o risco de danos catastr6ficos e/ou irreversiveis; (5) na tentativa de

salvaguardar-se das responsabilidades financeiras e ambientais, o 6rgao regulador pode ser

acusado de discriminar contra pequenas e recem formadas concessionfuias.

A atual situayao dos 6rgaos reguladores e complexa. Como mostra o hist6rico de vfuios

paises, as responsabilidades negligenciadas ou ignoradas por 6rgaos reguladores durante esta fase

serao eventualmente trazidas ao conhecimento publico que, por sua vez, responsabilizara o 6rgao

regulador.

Algumas organizayoes nao governamentais (ONGs) tern utilizado eficientemente diversos

mecanismos de marketing como ferramentas de informayao, e em alguns casos desinformayao,

promovendo investidas contra a industria e 6rgaos reguladores. Dentro deste cenfuio, o governo

nao tern como se exonerar das responsabilidades financeiras deixadas por companhias insolventes

ou negligentes, e busca meios de reduzir seus riscos fornecendo incentivos financeiros para o

cumprimento das obrigayoes ambientais, restringindo assim a participayao de concessionfuias nao

qualificadas. A tarefa nao e simples pois alem de diminuir seus riscos, o 6rgao regulador precisa

manter o setor competitivo e atrativo para manutenyao e ampliayao do fluxo de investimentos.

Os metodos de regulamentayao tradicional (Sistema de Comando e Controle ), tern algum

sucesso no controle do desempenho ambiental durante a vida de urn projeto, mas nao sao capazes

de garantir que as obrigayoes ambientais de final de contrato sejam satisfatoriamente cumpridas.

xxiv

Ja os Mecanismos de Incentivo Financeiro (Sistema de Mercado) vern sendo utilizados com

sucesso para o mesmo prop6sito.

Dentro dos setores de petr6leo e mineravao, mecanismos de garantia financeira ja sao

comurnente aplicados para garantir o cumprimento de obrigayoes ambientais (bond de

performance) durante a fase de abandono e reabilitas;ao (mine closure). Atualmente, este conceito

vern sendo estendido para abranger todas as fases de urn projeto (licitav5es, exploravao,

desenvolvimento, produs;ao, abandono e p6s-abandono ), inclusive para garantir o pagamento de

obrigas;oes financeiras eo curnprimento de prazos (bondsfinanceiros).

Os setores de mineravao e petr6leo tern atraido excessiva controversia em decorrencia de

varios problemas ambientais associados com empresas negligentes, irresponsaveis e nao

capacitadas. A industria esta preocupada com a imagem negativa que o setor vern ostentando

nessas situas;oes. Por esta razao, varios de seus representantes, principalmente grandes empresas,

concordam que existe a necessidade de uma regulamentas;ao exigindo garantias financeiras.

0 objetivo maior deste trabalho e o de fornecer inforrnavao sistematizada para auxiliar

agencias reguladoras no processo de elaboravao de urn sistema regulat6rio de garantia financeira

que seja verdadeiramente pratico e eficaz, garantindo e/ou custeando as obrigas;oes ambientais

ex-post (de final de contrato) atraves: (1) da geras;ao de incentivos reais e eficazes fazendo com

que a industria atue com responsabilidade; (2) do atendimento das atuais demandas de

preservavao ambiental; (3) do atendimento das necessidades da industria perrnitindo a

competitividade e a manutens;ao do fluxo de investimentos no setor de exploras;ao e produvao de

petrol eo e gas natural (E&P); e ( 4) da identificas;ao de mecanismos de salvaguarda protegendo o

6rgao regulador, e no fim, o contribuinte, de arcar com o onus financeiro deixado por

concessionlirias insolventes ou negligentes.

Dentre as contribuiv5es desta tese, destacam-se a parte conceitual, fornecendo defmis;oes

que perrnitam a sistematizavao da discussao, e a parte empirica, fornecendo urna ferramenta

capaz de auxiliar reguladores e industria no processo decis6rio gerando fluxos de caixa e analises

de sensibilidade. As principais contribuiv5es podem ser sintetizadas em: (1) uma classificavao

sistematica para danos ambientais que ocorrem ao Iongo de projetos de petr6leo no setor E&P

( danos acidentais, continuos, e ex-post); (2) urna discussao sobre custos ambientais dentro do

setor; (3) definivao de duas categorias distintas de garantias financeiras atualmente utilizadas e

que, apesar de sempre referidas pela mesma denominas;ao, "bonds", se comportam de maneira

XXV

diferente, almejando objetivos diferentes e, conseqiientemente, atingindo resultados diferentes

(bonds financeiros e bonds de performance); (4) identifica91io e descri91io de instrumentos

financeiros propondo uma classificayao inovadora para os vanos tipos utilizados como garantia

financeiras hoje disponiveis no mercado; ( 4) uma ferramenta decisoria que permite empresas e

organismos reguladores antecipar os potenciais impactos financeiros de suas decisoes, inclusive

decisoes sobre o tipo de instrumento a ser utilizado como garantia financeira.

As ferramentas decisorias desenvolvidas auxiliam na redu91io dos impactos financeiros

oriundos da implementayao de regulamenta96es ambientais na rentabilidade de projetos de

petroleo. Para tanto, neste trabalho sao propostos alguns exercicios de modelagem decisoria

interativa, permitindo a visualizayao dos impactos no fluxo de caixa do projeto possibilitando aos

tomadores de decisao trabalhar com diversos cemmos, alterando variaveis, simulando

contingencias, antecipando os impactos financeiros de suas decisoes, testando o impacto

financeiro das vanas op96es de instrumentos de garantia fmanceira disponiveis no mercado e,

principalmente, visualizando solu96es que nao seriam tao 6bvias de outra forma.

Para que seja viabilizada a elaborayao de urn modelo decisorio como proposto acima, faz

se necessaria uma ampla descriyao do sistema de garantia financeira e dos instrumentos

disponiveis, alem de vanas questoes envolvendo o tema descomissionamento de plataformas

maritimas.

As principais motiva96es para esta tese sao: (I) as grandes quantias envolvidas em

questoes ambientais, principalmente no descomissionamento de instala96es maritimas; (2) o

evidente nivel de ineficiencia do atual sistema de regulamentayao ambiental "Comando e

Controle"; (3) a experiencia positiva do sistema de garantia financeira acompanhada em vanas

partes do mundo; ( 4) a atual tendencia mundial da aplicayao de mecanismos de incentivo para

fazer valer as exigencias ambientais ex-post; e ( 5) a inexistencia de uma ferramenta decisoria

integrada para avaliar os impactos da aplicayao de diferentes instrumentos de garantia financeira

em diferentes cenanos.

Dentre as principais variaveis do modelo proposto estao: (!) as vanas op96es de

descomissionamento possiveis; (2) as op96es de instrumentos financeiros disponiveis no mercado

e aceitas como garantia fmanceira para opera96es de descomissionamento; (3) o tipo de

tratamento fiscal dado aos gastos com as opera96es de descomissionamento e aos gastos com a

aquisi91io de instrumentos de garantia financeira; ( 4) os parametros inerentes dos projetos, como

xxvi

dimensao, duras:ao, etc.; (5) o desempenho operacional do projeto e (6) a variaveis de mercado,

como pres:o do oleo, inflas:ao, taxa de juros, varias:ao cambial, etc.

0 sistema de garantia financeira descentraliza o processo decis6rio, estimulando o

comportamento adequado de empresas, definindo seus objetivos de desempenho ambiental e nao

urn protocolo de as:ao a ser estritarnente seguido. Com isso, da-se uma motivas:ao ao

desenvolvimento de tecnologias inovadoras capazes de reduzir a possibilidade de problemas

ambientais e, principalmente, reduzir os custos de descomissionamento. Alem disso, a exigencia

de garantia fmanceira assegura a disponibilidade de recursos e elimina a possibilidade de futuros

litigios. Neste contexto, as empresas sao obrigadas a intemalizar seus custos ambientais (ex-post,

continuo e acidentais), e, voluntariamente, monitorar as conseqiiencias de suas decisoes. Em

outras palavras, as companhias assumem a responsabilidade financeira de final de contrato de

demonstrar que o suas obrigas;oes ambientais, principalmente obrigas:oes ex-post como

descomissionamento, ocorrerao de forma satisfat6ria, fazendo com que o risco financeiro seja

transferido das vitimas (govemo e contribuintes) para os causadores (produtores e operadores ).

Desta forma, as autoridades salvaguardam-se de riscos tecnicos e financeiros, inclusive de

encerramentos prematuros ou nao planejados.

Existe uma grande variedade de tipos de instrumentos financeiros disponiveis para

garantir operas:oes de descomissionamento, alguns oferecem generosas flexibilidade e outros

significativos pesos financeiros. Todos porem, causam algum tipo de impacto, seja impactos

diretos, como custos de oportunidade, ou indiretos, como redus:ao da capacidade obtens:ao de

emprestimos. No entanto, uma bern elaborada regulamentas:ao e a aplicas:ao adequada da

engenharia financeira, permitem a aplicas:ao eficiente do sistema de garantia financeira, sem

desestimular investimentos no setor.

Dois tipos de mode los decis6rios serao oferecidos: ( 1) urn algoritmo computacional

denominado Petrobond e (2) urn modelo produzido com a ferramenta STELLA®. Dentro do

planejamento estrategico de projetos de petr6leo off.shore tais modelos permitem: simplificar e

sistematizar o conhecimento disponivel; diagnosticar, interpretar e discemir os dados; interpolar,

extrapolar e prever resultados; julgar incertezas; avaliar a sensibilidade dos parametros

envolvidos; e interpretar e avaliar as diferentes altemativas e cenanos. Essas ferramentas

possibilitarn tambem solus:oes 6timas que nao seriam 6bvias de outra forma, permitindo a crias:ao

urn de cenario de diagramas dinamicos.

UN I CAtV:

xxvii

Simula~oes confirmam o presente cenario, onde 6rgaos reguladores tendem a exigir bonds

do tipo surety, cartas de credito, e contas do tipo cau~ao com pagamentos peri6dicos. Analises de

sensibilidade de resultados de Valor Presente Liquido e Por~ao Govemamental indicam que

ap61ices de seguro do tipo ex-post, bonds do tipo surety, e cartas de credito podem causar

impactos menores permitindo melhores resultados. Simulayoes tambem confirmam que projetos

pequenos sao geralmente severamente afetados quando instrumentos do tipo colaterais, como

contas cau~oes, sao utilizados.

Quanto it terminologia empregada em portugues, o autor argumenta o seguinte:

1. A aplicayao do termo "abandono", tanto para o projeto como urn todo, ou como para o

tamponamento de poyos ("well plugging and capping") ou para o descomissionamento de

instalayoes maritimas (remoyao e disposi9ao ), nao sugere uma atividade confiavel. 0

termo parece ser "politicamente incorreto" ja que "abandono" exprime a ideia de "deixar

sem cui dado", o que nao faz justi~a ao verdadeiro objetivo das opera9oes de final de

contrato de explora9ao e produyao de petr61eo.

2. Os termos "cessayao", "desativayao" ou "encerramento", sao suficientemente amplos para

descrever as atividades de retirada, transporte e disposiyao final de instalayoes maritimas.

Estes termos parecem ser ideais para descrever todo o processo que inclui as varias

atividades de final de contrato de concessao visando a reabilita9ao dos danos ex-post,

mas, no entanto, nao exprime com clareza a especifica operayao de retirada e disposiyao

de instalay5es maritimas.

3. 0 termo "descomissionamento" e utilizado no Brasil para a "descontinua~ao" da

utilizayao de embarcayoes maritimas. 0 autor considera que as instalayoes maritimas

(plataformas, reservat6rios, etc.), ass1m como embarcayoes maritimas, sao

"comissionadas" para uma atividade especifica e depois, ao se tomarem desnecessarias

( seja por motivos tecnicos ou economicos ), estas tambem devem ser "descomissionadas".

4. 0 termo ingles "decommissioning" ja vern sendo amplamente adotado pela industria

mundial, e mesmo que nao houvesse uma palavra portuguesa correspondente

("descomissionamento"), a aplicayao de uma palavra transliterada da original inglesa

tambem seria viavel. Alem do mais, a palavra "descomissionamento" ja vern sendo

natural e amplamente adotada pela industria no Brasil.

xxviii

A tese esta organizada em 6 capitulos: (I) Introduyiio, (II) Principal Conceitos, (III)

Descomissionarnento, (IV) Mecanismos de garantia Financeira, (V) Tratarnento Fiscal, (VI)

Mecanismos Decis6rios/Modelagem Economica, e (VII) Conclusoes. Ao final, quatro anexos

fornecem subsidies adicionais para a compreensao de alguns capitulos: (A) Questionano para

Avaliayao de Instrumentos, (B) Descomissionarnento de Instalayoes maritimas, (C) Algoritmo

Petrobond, e (D) Ferrarnenta de Modelagem Stella. No Capitulo ll, "Principais Conceitos", o

artigo "A Decision Model for Financial Assurance Instruments in the Upstream Petroleum

Sector", publicado na revista Energy Policy, urn veiculo internacional arbitrado, e reproduzido.

No Capitulo VI, "Mecanismos Decis6rios/Modelagem Economica", os artigos "An Exploratory

Analysis of the Environmental Bonding System for Upstream Petroleum Projects" e "IdentifYing

Potential Impacts of Bonding Instruments on Ojjshore Oil Projects", publicados respectivarnente

nas revistas internacionais arbitradas Natural Resources Research e Resources Policy, sao

igualmente reproduzidos.

xxix

CHAPTER I- INTRODUCTION

1.1. OVERVIEW

The world depends on fossil fuels for more than 60% of its total energy needs (ODCP,

1998). Offshore exploration became a very important energy source since it was discovered in

1947 in the Gulf of Mexico (GOM). In 1965, natural gas was discovered in the British portion of

the North Sea, followed by the discovery of oil in 1970. Furthermore, of great significance for

Brazilian economy, was the discovery of offshore reserves at Campos basin during the 1980's

(FORMIGLI and PORCIUNCULA, 1997).

There are over 7,270 offshore installations in place around the world, installed in the

continental shelves of more than 53 countries worldwide, of which 40 produce offshore oil and

gas in significant amounts (Figure 1.1). The present distribution of offshore installations is

approximately as follow: 4,500 in Gulf of Mexico, 950 in Asia, 750 in the Middle East, 457 in

North Sea, 445 in South America, 649 in Africa, and 53 in Australia (PROGNOS, 1997; ODCP,

1998; POREMSKI, 1998; PANE AND HENDARJO, 1998; GRIFFIN, 1996, 1997, 1998a,

1998b, 1998c, 2000a, 2000b). Retaining the record for deep-water completion, Brazil has

approximately 105 producing offshore platforms (ANP, 2003).

Offshore California

30

South America

340

Not1h Mrica

100

Asia

ll..950 all _.;~

Australia~ 53 'I> <P't;

Figure 1.1. World Platform Population. Numbers are compiled from a number of sources including government

reports, industry staff, and academic literature.

Although offshore installations must be decommissioned at the end of petroleum projects,

most offshore structures were not designed to be removed. In the next 20 years, between now

and 2025, it should be expected that over 6,500 installations will be decommissioned, and at an

estimated cost of US$ 20-40 billion (COLEMAN, 1998).

Several potential problems related to the abandonment of offshore installations have been

officially acknowledged since the 19 58 Geneva Convention on the Continental Shelf According

to CAMERON (1998), this sudden interest had two main motivations: (1) Maturing of several

large oil and gas provinces around the world turn decommissioning costs public. (2) The need

for offshore decommissioning has coincided with the growing impact of environmental concerns

in international affairs. In fact, the first "decommissioning boom" has landed right in the middle

of the international sustainable development agenda.

Decommissioning has become a very emotional issue, and, as illustrated during the over

publicized and politicized Brent Spar episode, compliance with all international, regional, and

domestic legal requirements may not necessarily be sufficient to satisfy the expectations of public

and interest groups. Presently, there is a movement in the United Nations Commission on

Sustainable Development to set up a Global Authority for offshore oil and gas operations (MMS,

1999a).

Based on estimated costs, offshore decommissioning may become in the near future one

of the major issues facing the global offshore petroleum industry. The impacts of

decommissioning expenditures in the profitability of offshore projects and government earnings

are significant and must be carefully considered. In this thesis, the author elaborates on the issue

of how to anticipate and reduce the impacts of environmental regulations upon the profitability of

offshore oil projects. Several approaches can be adopted to guarantee that all decommissioning

obligations will be met. This study focuses specifically on the application of the financial

assurance system, which is a form of financial security used to safeguard authorities against

environmental liabilities. Financial assurance systems and instruments can be found in the

literature with different denominations such as: financial surety, financial security, financial

guarantee, and bonds.

If financial assurance mechanisms (bonding mechanisms) are to be adopted, the key to

avoid investment migration from the sector is the implementation of reasonable policies, making

available different forms of bonding instruments that offer reasonable flexibility to companies.

2

Investment flow in the oil sector is a very important source of capital for economic development.

Impacts may also be reduced by the application of adequate financial engineering techniques and

comprehensive early decommissioning planning.

Although the author recognizes several other essential economic issues involved in the

decommissioning process (i.e. optimum period to initiate decommissioning activities; operation

method- single or phased approaches; removal and disposal options; technological innovations),

the focus in the present work is on the application of bonding mechanisms to guarantee the

satisfactory performance of decommissioning operations and other ex -post environmental

obligations. It includes:

• Identification of corporate environmental costs and liabilities related to ex -post

obligations;

• Identification and description of forms of bonding instruments currently available;

• Identification and description of existing fiscal regimes in what ex -post environmental

costs and bonding-related expenditure are concerned;

• Simulation of offshore oil-producing fields in the Brazilian Outer Continental Shelf

(OCS) where different bond options are tested in a series of discounted cash flow

scenario analyses based upon the current Brazilian fiscal regime; and

• Suggestion of a decision tool, which will allow the assessment of the potential

financial impact caused by different bond options upon the profitability of offshore oil

and gas projects.

A hypothetical scenario is proposed based on existing bonding regimes around the world,

mainly in the USA and Canada. Some alterations are made in order to adjust proposed bonding

policies to new areas open for investment.

1.2. PURPOSE AND JUSTIFICATION

The present work involves two key themes: The decommissioning of offshore

installations and the application of financial assurance mechanisms. Academically, both subjects

are under explored. Decommissioning-related issues have been increasingly attracting the

interest of the industry, government, and interest groups. Since 1995, several technical articles

and some academic papers have been written on decommissioning-related issues. The literature

record on the application of financial assurance mechanisms in the oil industry is rather scarce.

3

Most information on bonding mechanisms must be extracted from books on financial incentive

tools, official documents (regulatory literature) on financial assurance legal requirements, and

from interviews with bonding experts from regulatory agencies and the financial sector.

In Brazil, for instance, very little has been done on both areas. ANP is just beginning to

deal with end-of-leasing obligations, including ex-post environmental operations such as

decommissioning. Very little is known about the end-points of Petro bras' redundant platforms.

In 2002, ANP defined well abandonment rules for the Brazilian industry. Petrobras has recently

initiated internal studies and activities aimed at improving company's knowledge on

decommissioning and other ex-post related matters (ANl', 2000b). ANP has recently intensified

its interest on decommissioning issues what lead to the establishment of a technical consulting

project, a research partnership between State University of Campinas (UNICAMP) and the

Agency. At the beginning of this project, the present theme was merely an academic essay

proposing an eventual application of financial assurance instruments on new oil frontiers in

Brazil. Today, as Brazilian authorities in accordance with international conferences and treaties

are developing sound decommissioning regulations, the establishment of a Brazilian financial

assurance regime involving several ex-post offshore activities is very likely. Progressively being

implemented, financial bonds1 are already required to guarantee contractual obligations in the

bidding process (letters of credit).

The main motivations for a comprehensive study on the application of financial assurance

mechanisms are:

• Large sums of money involved in meeting decommissioning obligations, which can

significantly impact offshore oil projects at the end of their productive lives;

• The noticeable inefficiency of the current command and control regulatory system;

• Encouraging results increasingly obtained from regulatory agencies currently adopting

fmancial assurance mechanisms around the world;

• The perception of a trend in which agencies from different countries begin to adopt

economic incentive mechanisms to deal with the uncertainties of environmental

regulations; and

• The lack of quantitative studies and publications involving the application of financial

assurance mechanisms and their potential impacts on oil projects.

1 A fmancial token claiming that the bid will be honored and areas will be explored.

4

No bonding requirements should be adopted in the oil sector without a comprehensive

assessment of their economic impacts. Wrong decisions may drive away important investments.

For this reason, Chapter VI is devoted to the proposal of a decision model aimed at anticipating

the financial impacts upon the profitability of offshore oil projects caused by the different forms

of financial assurance instruments. Decision models are essential for managing oil projects, and

for simulating potential effects of requirements being proposed by authorities. A well-designed

flexible financial assurance system is likely to maintain the flow of investment in the sector and

at same time preserving the industry and authorities from the kind of wearing off observed during

the Brent Spar episode.

1.3. METHODOLOGY

The main steps for achieving the proposed products of this research project are illustrated

on Figure 1.2. Information on decommissioning was gathered through literature research,

reviews of documents of several countries, periodicals, and interviews conducted with

decommissioning managers and government officials via electronic mail, telephone, and

specially arranged meetings in the United States, the Netherlands, Norway, and Brazil. Important

technical literature on decommissioning has become available in recent years. The majority of

government documents has been acquired directly from the competent agencies.

Most specialists were involved in the areas of hardrock and coal mining, and onshore and

offshore upstream petroleum recovery; all in the United States and Canada. This process is

illustrated in Figure 1.3.

In this thesis, the author attempts to answer the following questions:

• Question 1: How to guarantee that oil and gas leasing areas will be ultimately returned in

environmental conditions at least similar to preexisting ones?

• Question 2: How to ensure that all ex-post (end-of-leasing) obligations will be satisfactorily

met, safeguarding public environmental and economic interests by maintaining investments in

the sector and, simultaneously, providing protection against insolvent and negligent lessees,

and eventual unplanned closures?

5

~··.~·~· .. ~. '· assessment i '·

0 eXJ 1stng n lng 1 '· instruments ) '· specialists J

Regulatory cost analyses

sy ems

Analysis 1 Bonding systems & instruments , , Decommissioning regimes & options [

I Financial impact

analyses

-------------• Evaluating impacts on Evaluating impacts on ~-------------·c the regulatory agency the upstream industry

Meets agency's needs?

J

I Hypothetical Model ~No·--~

Test& Evaluation

I Yes / Meets \

;,.•------'--------.(• industry's \

~ I Select instruments ._yes

to run simulations ~ _. Select bonding system

es to run simulations

Figure 1.2. Flowchart of main project activities.

6

• Question 3: How to make such a regime viable?

• Question 4: How to anticipate and attenuate the financial impacts caused by each of the

different forms of performance bonds required as guarantee for the fulfillment of ex-post

environmental obligations?

Literature Industry

Government

Decommissioning 0 ptions

Bond Options

Figure 1.3. Methodology for approaching proposed goals.

Best 0 ption

Question one through three involves the conceptual part of this thesis. Part four involves

the empirical part. In order to approach the forth question, a variety of financial instruments that

are available to be applied as financial guarantees in offshore oil projects were identified. How to

decide on the best option, the one that will offer the least cash flow impact? How to select the

bond instrument that will allow the ultimate maximization of project value?

Main Parameters includes:

• Existing decommissioning legal framework and potential trends.

• Existing financial assurance regimes.

• Existing fiscal regimes.

• Existing historical data

• Existing decision models.

• IdentifY:

o Static Parameters

o Probability Distribution Parameters

o Dynamic sub-model simulations

7

The construction of a basic tool to work out the problem: the economic analysis technique

is primarily based upon a discounted cash flow. The main economic analysis output will be the

Net Present Value (NPV). The reason for using the discounted cash flow method for the

economic analysis is to present a systematic and quantitative approach for problem solving, in

addition this method can be easily implemented by oil companies2.

• Economic Analysis: evaluation of the relative merits of situations - profit and cost

viewpoints.

• Financial Analysis: behavior of funds - what are the instruments that allow the best

yields?

• Intangible Analysis: consideration of factors that affect project but which cannot be

easily quantified.

A decision model was designed in order to test all financial assurance mechanisms and

compare them against available data using the algorithm Petro bond (Appendix C). The strategic

planning of offshore oil projects, allows: the simplification and systematization of the available

information; sensitivity evaluation of important parameters involved; and the interpretation and

evaluation of different alternatives and scenarios. Petrobond also provides a way of finding

optimum solutions, which would not be obvious otherwise. For this same purpose, a

complementary decision model using the STELLA® software is also proposed (Appendix D).

Approaches used to incorporate risk and uncertainty into analysis:

• Sensitivity Analysis: used to evaluate the effects of uncertainty on projects by

determining the variation of investment.

• Probabilistic sensitivity analysis: used to account for the uncertainty associated with

possible variation in project parameters and expected present value to account for risk

associated with finite probability of failure.

1.4. LITERATURE REVIEW

Until 1995, articles on decommissioning of offshore installations were scarce. The Brent

Spar episode triggered a boom in the specialized literature. One of the first important works on

the subject was the PROGNOS (1997), a socio-economic report on impacts of varying

2 The designation "oil companies" includes other parties that may be responsible for the performance of closure activities (i.e. operators, individuals, lessees).

8

decommissioning options. This study was done in London in behalf of the Offshore

Decommissioning Communications Project (ODCP), and carried out by PROGNOS. Several

other studies were conducted by agencies and the industry. The Phillips Petroleum Norway, has

been conducting cost assessment studies since 197 5, but most of these studies have not been

published.

The literature record on the application of financial assurance systems within the upstream

petroleum sector is especially limited. Nearly all information is extracted from internal

government publications and reports, and a few sprinkled lines in legal publications. The

application of financial assurance mechanisms in the US coal industry is particularly well

documented and can be used for a better understanding of the different bonding instruments

presently available.

COSTANZA and CORNWELL (1990, 1992), and CORNWELL and COSTANZA (1994,

1999) have comprehensively written about environmental assurance bonding. Their work should

be used as an important reference on the general application of such mechanisms. Documents

from regulatory agencies (MMS, 1998, 1999, 2002; OSM, 1987, 2000a; BLM, 1995, 1996; ANP,

2000a, 2002a; EPA, 1995, 1997; etc.) provide additional decommissioning and bonding

information. GRIFFIN (1996, 1997, 1998a, 1998b, 1998c, 2000a, 2000b) has extensively written

about offshore decommissioning. Related information and decommissioning data has also been

obtained from Bill Griffin's presentations and lectures. MILLER ( 1998), a study prepared for the

International Council on Metals and the Environment (ICME), represents an important and

extensive work on the application of bonding instruments on the hardrock mining sector. 1\'WF

(2000) describes in detail the current situation of the hardrock mining sector, which is under a

very lenient bonding regime. FERREIRA and SUSLICK (2003a) defines several concepts

related to bonding mechanisms. It also provides a systematic classification for financial

instruments used to fulfill bonding requirements.

9

CHAPTER II- MAIN CONCEPTS

Which are the main contributions offered by this thesis work? Were there significant

contributions to the advancement of knowledge in this area? Answer: The present work

systematizes a series of concepts and describes aspects of the financial assurance systems that

were not previously defined:

• Proposes a classification for different forms of environmental damages in the upstream

petroleum sector (e.g. accidental, continuous, and ex-post);

• Defines the terminologies "financial bonds" and "performance bonds", which have been

interchangeably used disregarding the fundamental difference between them;

• Presents a comprehensive assessment of currently available financial assurance mechanisms

and instruments;

• Proposes an innovative, systematic, and ample classification for available financial

instruments. The lack of such tool has caused significant misunderstandings in the debate of

bonding systems;

• Presents a series of modeling exercises with the STELLA® modeling tool, simulating project

cash flows for oil projects under different bonding regimes in order to assist in the decision

making process;

• Presents a complex decision toll for managing offshore oil projects under bonding regimes.

This tool, an algorithm denominated Petrobond, is aimed at anticipating the potential

financial impacts of several bond alternatives and bonding requirements, providing a

practical tool for both industry and regulators (FERREIRA eta!., 2003); and

• Offers an exhaustive set of references for both themes, decommissioning of offshore

installations and financial assurance mechanisms.

All the above items should ultimately contribute to the development of sound bonding

systems that will fund or guarantee ex-post environmental obligations within the upstream sector.

They should also identify a portfolio of bonding instruments capable of providing coherent

flexibility to companies, maintaining competitiveness within the sector and meeting the needs and

aspirations of the regulatory agency

10

In this chapter, a conceptual article was prepared in order to deepen the current

discussion involving financial assurance tools and their effectiveness in providing adequate

guarantee for ex-post obligations in the upstream oil sector. In addition, this article presents a

multiattribute decision model that attempts to explain the current choice of instruments by both

regulators and industry.

I. REFERRED ARTICLE I- Energy Policy, pnblished in 2003

TITLE: A DECISION MODEL FOR FINANCIAL ASSURANCE INSTRUMENTS IN

THE UPSTREAM PETROLEUM SECTOR

AUTHORS: Doneivan Ferreira(!) "; Saul Suslick(J)(Z); Joshua Farley<3>; Robert Costanza<3>;

Sergey Krivov(3>.

(I)Department of Geology and Natural Resources - State University of Campinas (UN/CAMP),

P.O. Box 6152, Campinas, SP 13083-970 - BRAZIL; <Z>center for Petroleum Studies

(CEPETRO), P. 0. Box 6052 Campinas, SP 13083-970- BRAZIL; and <3>/nstitute for Ecological

Economics (lEE) - University of Maryland, Box 38, Solomons, MD 20688- USA.

ABSTRACT

The main objective of this paper is to deepen the discussion regarding the application of financial

assurance instruments, bonds, in the upstream oil sector. This paper will also attempt to explain

the current choice of instruments within the sector. The concepts of environmental damages and

internalization of environmental and regulatory costs will be briefly explored. Bonding

mechanisms are presently being adopted by several goverrmients with the objective of

guaranteeing the availability of funds for end-of-leasing operations. Regulators are mainly

concerned with the prospect of inheriting liabilities from lessees. Several forms of bonding

instruments currently available were identified and a new instrument classification was proposed.

Ten commonly used instruments were selected and analyzed under the perspective of both

regulators and industry (surety, paid-in and periodic-payment collateral accounts, letters of credit,

self-guarantees, investment grade securities, real estate collaterals, insurance policies, pools, and

11

special funds). A multiattribute value function model was then proposed to examine current

instrument preferences. Preliminary simulations confirm the current scenario where regulators

are likely to require surety bonds, letters of credit, and periodic payment collateral account tools.

2.1. INTRODUCTION

Due to current world developments and to the ever-increasing demand for nonrenewable

fossil fuels, goverrunents are likely to intensifY exploration and production efforts, including

small and marginal fields. In fact, several traditional and nontraditional producing nations have

already established tax incentive policies and royalty relief programs. These policies and

programs are based on the perception that oil imports carry profound economic and political

costs, which are intensified during times of international instability. Even though governments

are interested in maintaining (and improving) investment flow and competitiveness within the

sector, safeguarding taxpayers against industry's environmental noncompliance costs is

becoming a critical issue.

The scenario described above calls for a number of considerations regarding a desirable

balance between the public outcry for environmental accountability and the industry pressure for

regulatory flexibility. Regulators are mainly concerned with the noncompliance risk offered by

the increasing interest of newly formed and small companies in small and marginal fields

(HAYNES, 1994; MMS, 2000a, 2001; ANP, 2000b, 2002a; DTI, 2000; BRYAN, 2000;

MARTIN, 2000; WILLIAMS, 2000; MIRABELLA, 2000; BLM, 2001; BAIER, 2001;

CORNWELL, 2001; NPD, 2001; MPC, 2001; STOKES, 2001). In addition, without protection

mechanisms, large companies could open small spurious companies to evade closure liabilities.

Owing to the evolution of social consciousness and pressure from interest groups,

regulators are being compelled to establish stringent environmental policy requirements,

including incentive mechanisms aimed at safeguarding society against environmental

degradation and related fmancial liabilities (FERREIRA and SUSLICK, 2001). Financial

assurance requirements (bonds) come as a response to environmental compliance concerns in the

oil sector, where it is being used to reduce the risk of noncompliance on end-of-leasing

contractual obligations3• Several countries have adopted bonds in order to cope with these ex-

3 Recent events tend to significantly affect the political behavior among larger fuel consuming nations. At least initially, a regressive trend may be perceived on environmental policies. This may occur because in order to reduce fuel dependency from

12

post liabilities in the petroleum sector; among them, Canada, United States, United Kingdom,

Australia, and Brazil.

The application of bonding mechanisms is a complex subject involving a great deal of

controversy. The scope of this paper is limited and solely directed to the application of bonding

instruments within the upstream petroleum sector aimed at ensuring compliance with closure

obligations (reclamation, abandonment and decommissioning operations). As will be explained,

these activities are specifically associated with the process of mitigating ex-post environmental

damages, providing and enforcing conditions of negligible health and safety risk to local

inhabitants, and ensuring safety for navigation and the environment.

The present work does not focus on the nature or scale of potential environmental

impacts; instead, it provides elements in a systematic effort to broaden the current discussion

involving the application of bonding instruments in the Exploration and Production sector (E &

P). This paper is divided into three sections. The first section describes different forms of

environmental damages and presents an overview of environmental costs. It discusses some

important concepts, such as assessment of monetary value of environmental damages and

internalization of environmental costs. Section 2 briefly describes the main forms of regulatory

approaches, explains the application of bonding mechanisms in the upstream petroleum sector,

identifies and analyzes a number of bonding instruments currently being used in the sector, and

proposes a systematic instrument classification. The last section offers a decision model to

explain the current instrument choice among regulators and the industry.

2.2. FORMS OF ENVIRONMENTAL DAMAGES

Upstream petroleum activities have the potential of generating a wide range of

environmental impacts (chemical, physical and biological disturbances). Such impacts may be

manifested in the surface and subsurface, in the water and water bottoms, and in the atmosphere.

In order to better assess potential environmental impacts, PATIN ( 1999) suggests a

special classification for the development phases, taking into consideration the respective

sequence of operations: (1) geological and geophysical survey (seismic surveys, test drilling,

etc.); (2) exploration (rig emplacement, exploratory drilling, etc.); (3) development and

unreliable and hostile foreign sources, governments may be tempted to relax environmental regulations for the upstream sector. However, in due course, domestic and international pressure should force them back on track towards more stringent environmental regulations, including the adoption of bonding requirements.

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production (platform emplacement, pipe laying, drilling, extraction, separation, transport, well

and pipeline maintenance, etc.); (4) closure and decommissioning (disassembling, structure

removal, well plugging, site clearance, land reclamation, etc.).

FERREIRA and SUSLICK (200 I) propose tbree broad categories of environmental

damages within the specific context of hydrocarbon recovery: ex -post, accidental and continuous

environmental damages (Figure 2.1). This classification was previously used by CORNWELL

(1997) to explain the role of incentive tools on environmental regulation. This proposed tool

helps to systematize the present discussion, assisting in the optimum application of bonding

mechanisms.

Accidental Damages

This category includes environmental impacts caused by oil companies in unforeseen

events during the course of daily operations. Levels of risk are assigned according to the

availability of statistical data on specific events. For instance, an oil company may have control

over some contingencies, making it possible to reduce the risk and intensity of accidental

damages. In other cases, there is no control over events and no possibility of risk reduction.

Examples of accidental damages: blowouts, accidental spillage, accidental discharge of drilling

muds or produced waters, sinking of offshore installations, vessels or helicopters, acts of God

(flood, lightning, earthquake, etc.), war, sabotage, terrorism, etc.

Continuous Damages

This category includes environmental damages resulting from on-going processes during

the life of a project. Examples of continuous damages are: discharge of drilling muds and

cuttings, emissions and discharge of pollutants, deforestation and other physical disturbances,

generation of solid waste, emission of waste in streams, sediment resuspension, interference with

humans, fisheries and other users, etc.

Ex-post Damages

This category includes environmental damages that are anticipated as a result of upstream

oil activities. In this case, provisions for the remediation or mitigation of such damages are

arranged before leases are granted for a specific project. For instance, companies conducting

14

offShore operations are required to reclaim the site by plugging and abandoning all wells,

decommissioning all offshore installations and clearing the site of all obstructions. These

operations take place at the end of a project, phase, or specific activity. The emphasis lies on

achieving proper closure rather than on the closure process. In this case, regulators are not

interested in monetary compensations, but rather in the fulfillment of closure obligations. In

order to maximize project value, oil companies are motivated to avoid costs of repairing

damages, and pursuing less costly closure alternatives.

ProWction Begins

Lease is

1;'::1expaa~' '!!:~:f.~:·.~~t __ ,_! .. Prod.!:!;::·riia:w1 -~~~ ,,,,,-:::::::1 -

I -............ ~ Accidenlal t:a nages

Figure 2.1. Environmental Damage Categories. The life of an oil project, its phases, and potential for environmental damages (FERREIRA and SUSLICK, 2001).

Some examples of ex-post mitigating activities include: plugging and abandonment of

wells, removal and disposal of offshore platforms and pipelines, removal and disposal of debris

and obstructions on the ocean floor, site reclamation, revegetation, removal of constructions and

access roads, etc.

As also concluded by CORNWELL (1997), this is perhaps the best-suited category to be

covered by bonds. In the upstream oil sector, some of the corroborating factors are: (I) oil

projects have limited time horizons (a defined beginning and a defined end); (3) operations

require a lease (or license) before they are undertaken; and (3) in most circumstances, costs for

mitigating ex-post damages caused by upstream activities can be easily estimated (i.e. cost for

plugging wells).

Some of the arguments that make the oil sector more convenient for the application of

bonding regulations include:

• Petroleum exploration and production operations involve significantly smaller areas than

other extractive activities.

• In most circumstances, because of the potential for significant government revenue

earnings, oil projects are subjected to more scrutiny and more rigorous licensing

processes.

• Currently, due to the costs involved in the licensing, exploration, and development

phases, in most cases, oil and gas projects attract fewer risky parties when compared to

the mining sector, for instance.

• The potential for ex-post environmental damages in petroleum projects is significantly

small when compared to potential ex-post damages in mining projects, for instance4•

Nevertheless, a number of emerging issues are likely to introduce some complexity in

estimating costs of ex -post damages in the oil sector:

• Decommissioning of large fixed offshore installations: the industry does not have real

experience in the decommissioning of large fixed platforms. Consequently, due to

technological uncertainties, estimating decommissioning costs is a very controversial

ISSUe;

• Decommissioning of pipelines: so far, regulators do not require the removal of pipelines.

However, this scenario may change bringing significant environmental and financial

uncertainties to the closure process;

• Cleanup of offshore sites: currently, there is significant discussion involving requirements

for the removal and disposal of drill cuttings generated in offshore operations. As

4 The internalization of ex-post environmental obligations is a very controversial issue. For instance, if ex-post costs are truly and ultimately internalized and transferred to the fmal user, as it should, what would be the cost of nuclear energy? Costs related to the decommissioning of nuclear power plant, storage of wastes, perpetual monitoring of radioactive waste is enormous, but such costs are never internalized and someone will eventually have to cover them. The same has been happening in the upstream oil sector where before the problem emerged during the Brent Spar episode, the cost for removing and disposing of offshore structure was largely ignored and never internalized.

16

regulatory standards for offshore site cleanup toughen, uncertainties will be introduced to

the ex -post cost estimation process;

• NORMs: the presence of Natural-Occurring Radioactive Material (NORMs) in waste,

fluids and gases brought to the surface from producing subsurface oil and gas formations

has become a great concern for the oil industry (MCFADDING, 1996). Long-overdue

handling and disposal requirements for NORM-bearing waste and contaminated

equipment will significantly impact ex -post costs;

• Residual liability: the discussion on potential residual liability is also expected to add

significant uncertainty to this debate: "when can a company walk away'' or "when is

liability over".

Although the application of bonds is mostly suitable for providing protection against ex

post damages, it may indirectly generate incentives for the reduction of continuous and accidental

damages. Bonds may be appropriate to cover accidental damages if the probabilities for

contingencies are known and if potential damages are not catastrophic or irreversible. There is a

wide spectrum of possible continuous damages, and the applicability of bonding mechanisms

depends on the nature and extent of the damage.

2.3. FINANCIAL ASSURANCE SYSTEMS A.l'o;'D INSTRUMENTS

The main approaches to environmental policies are Command and Control (direct

regulation) and Economic Incentive Mechanisms (market alternatives). Both Command and

Control (CAC) and Economic Incentive Mechanisms (ElM) have been exhaustively discussed in

the literature, including their characteristics, applications, and efficiencies (BOHM, 1981;

STOLLERY, 1985; WEBBER AND WEBBER, 1985; CONRAD, 1987; BAUMAL and OATES,

1988; PERRINGS, 1989; CORNWELL, 1997).

CORNWELL and COSTANZA (1994) compare CAC and ElM approaches, and some

aspects are here adapted to the offshore oil sector: The CAC approach consists of establishing

and enforcing laws and regulations, and of setting objectives, standards and technologies with

which agents must comply. The ElM provides incentives that encourage the desired behavior

while allowing firms the flexibility to act on their unique knowledge of their own production and

mitigation costs. This decentralizes the decision-making process to protect lease areas; and it

17

relies on performance objectives rather than on a pre-established course of action. Economic

analysis indicates that present methods of environmental protection, mostly based on CAC

strategies, are inefficient and often provide disincentives for directing resources toward

abatement. The main causes are: (I) great uncertainties in calculating decommissioning and

other ex-post costs; (2) costly and lengthy litigious processes involving oil companies and other

key stakeholders; (3) unfair homogeneous treatment of oil companies (no record-based

assessment); (4) great information burden on the regulatory agency (selecting the best

technology, enforcing penalties for noncompliance, monitoring lessees and financial institutions);

( 5) little incentive for the development of innovations that can result in improvements and cost

reduction; ( 6) encourage regulatory evasion rather than regulatory compliance; and (7) vague

regulatory language allowing oil companies to build persuasive cases by showing that ex-post

requirements are unachievable.

Environmental Costs

The feasibility of bonding mechanisms will require that regulators and/or third party

insurers possess a reasonable estimate of the costs that the mechanisms will need to cover. If

costs are underestimated, the assurance is incomplete, and the regulator may be forced to cover

the shortfall. If the costs are overestimated, desirable investment may be deterred, or companies

may move their operations to countries with lower regulatory standards. What types of costs are

relevant, and how they are measured, depends on the type cost under consideration, as mentioned

above.

In the case of ex-post closure obligations, oil companies are required to meet a set of

standards determined by the regulatory agency. What is far more complicated is the process of

deciding on those standards. Once standards are defined, the costs for achieving those standards

are fairly simple to calculate, and will determine the amount that must be provided by the

bonding mechanism.

Intuitively, it would seem that the standard should be set so that there are no lingering

damages (i.e. costs), environmental or otherwise, after closure operations. In the extreme case,

this might require returning the site to the condition it was in prior to the start of the extractive

activity. However, closure operations entail considerable costs, and the more stringent the

standards set by the regulator, the higher these costs. In fact, it is likely that each step taken

18

towards site rehabilitation costs more than the previous one-eliminating the first 10% of the

damages may be fairly inexpensive, the second I 0% may cost more, and the final 10% required

to return the system to its pristine state may be very expensive indeed. A hypothetical marginal

cost of closure operation curve is shown in Figure 2.2. In contrast, the benefits to restoration

may be falling as the site approaches the 'pristine' state. Plugging a well is likely to have

enormous benefits in terms of preventing pollution, environmental degradation, and accidents.

Removing offshore infrastructures also has important benefits, though less than those of

plugging the well. Keeping offshore platforms in place or transporting them to artificial reef

locations raise a series of issues, including residual liability. However, the presence of offshore

structures does improve ecosystem services. Besides, the decision regarding the complete

removal of offshore structures should consider the internalization of all decommissioning costs

including emissions, energy consumption, safety risks, etc. (see Appendix D - ecological

impacts of decommissioning operations) As increasingly on-site contamination is cleaned up,

marginal benefits are likely to fall even further. This is shown by the marginal benefits to

closure operation curve in Figure 2.2.

0

marginal cost of decommissioning

~ marginal benefit from decommissioning

"--..

: ......... optimal : standard

s Site degradation/ environmental costs

Figure 2.2. Marginal costs and benefits of decommissioning operations. Intersection E indicates the point of optimum standard. Area OES indicates a low efficiency scenario, where costs ourweigh decommissioning benefits.

19

If the assumption is correct that the costs of restoration increase as we move towards

recreating a pristine system, and the benefits decrease, then at some point the costs will outweigh

the benefits (all points to the left of E in Figure 2.2). From the efficiency perspective, this is

entirely undesirable. To achieve the most efficient allocation of society's resources, regulators

should strive to set the standard at the point of intersection of the marginal cost and marginal

benefit curves. This, of course, is much easier said than done, as it shall be explained below.

On the other hand, what right does an oil company have to externalize costs transferring

the financial burden to society? Shouldn't polluters have to pay for the pollution they cause?

Even from the viewpoint of economics, efficient market outcomes require that producers pay all

of the costs associated with their production. Consider tax deductions, which imply cost sharing

between companies and government/taxpayers (FERREIRA and SUSLICK, 2001). In Figure

2.2, these costs are depicted by area OES, and are substantial. While Polluter Pay Principle

(PPP) should apply, closure standards are not the most efficient way to achieve this goal. The

resources that a petroleum company would require to completely restore a site are resources that

would become unavailable for society to apply towards other desirable activities, such as

plugging of orphan wells and sites that were negligently abandoned before bonds were required.

To enforce PPP, one option could involve a 'degradation' fee (equal to area OES) added to the

costs of meeting the ex -post enviromnental standard. Such a fee, if adjusted ex -post to reflect

actual degradation, could greatly increase the extent to which financial assurance instruments

help internalize externalities.

Most types of ex-post bonding instruments are a hybrid of market mechanisms and

command and control regulations. The ideal market mechanism would allow a firm flexibility in

the extent to which it performs closure operations, but force it to pay for all social costs it

imposes. Such a system takes advantage of the firm's internal knowledge of production costs,

clean up costs and profits. When closure is more expensive than social costs, the firm pays its

social costs. When closure is less expensive, the firm performs closure operations. Most

important in the dynamic setting, there is always an incentive to seek new technologies and

techniques that minimize environmental costs. In the case of bonds, the regulator must

determine the closure standard and is therefore less able to rely on the firm's internal knowledge.

However, in a number of ways, financial assurance does help improve market function. Bonds

force all firms to pay for at least some of the enviromnental costs they impose on society,

20

without risk of bankruptcy or non-compliance. Bonds force firms to incorporate environmental

liabilities directly into their cash flow accounting, and the costs are made explicit to

shareholders. As careful management of all phases of a project can substantially reduce ex-post

liabilities, firms have more incentive to minimize damage and avoid accidents throughout the life

cycle of the investment. Perhaps most important, firms cannot avoid these liabilities through

bankruptcy or refusal to comply. Firms have incentives to develop new technologies for

reducing environmental costs as long as the regulator and/or third party insurers take these into

account when determining bond requirements (consider that, in practice, regulatory agencies are

not very open to unproven technologies, reducing the incentive for the development of

technological innovations). Third party insurers are also likely to monitor projects, potentially

reducing regulatory costs in this regard (APOGEE/-HAGLER BAILLY with D. R. A.l'IDERSON

ASSOCIATES, 1998).

A serious problem with this analysis is that while closure operation costs are fairly simple

to estimate, the benefits of such operations are dramatically less so when the impacts include

damage to environmental services. There are a number or economic methodologies for

estimating the values of environmental services, including contingent valuation, hedonic pricing,

travel cost methodology, replacement costs, and others (PEARCE and TUR.l'<'ER, 1990). All of

these methodologies are inexact, and rely on a greater knowledge of ecosystem functions, the

way those functions benefit humans, and the impacts human activities have on those functions

than currently exists. Ecosystems are extremely complex systems, characterized by non

linearity, emergent properties, and non-reversibility beyond often-unknown thresholds (ODUM,

1997). The nascent science of complexity theory offers some insights into ecosystem function,

but is still inadequate to explain it (KAUFMANN, 1995). Instead of the fine line depicted in

Figure 2.2, marginal benefits of closure operations are better illustrated by a thick smear. With

so much uncertainty, the industry will pressure regulators to make the standards as vague as

possible, while the public may push for stricter standards. In keeping with the precautionary

principle, it is safer to err on the side of caution, and standards should be set closer to complete

restoration (COSTANZA, et al., 1997).

Bonding may help reduce the difficulty for regulators to estimate closure costs. If

standards are set for closure without bonding mechanisms to back them up, firms will have

incentives to overestimate closure costs so that regulators will require less complete closure

21

operations. With bonds however, firms have to pay in advance for closure costs, and lose the

incentive to overestimate. The question still remains whose costs should form the basis of the

estimate. The firm is likely to be able to meet closure costs more cheaply than the regulator,

because it will be able to use its own resources and avoid overhead. The government, in

contrast, will have to hire outside contractors, possibly at higher cost. However, as it is the

regulator that will have to bear the costs in the event of default, the more likely the firm is to

default, the more appropriate it becomes to use government costs (usually, estimations are based

on project plans provided by operators and confirmed by the regulator's database, and an

additional amount is included, usually 15 to 30%, to internalize indirect costs such as overhead

and third-party costs).

Bonding Systems

There are five main stakeholders involved in the bonding process: regulators, industry,

society, project financing agents, and bonding agents/third party insurers. The focus of this paper

is on regulators and the industry. Some key concerns associated with each stakeholder are

summarized on Table 2.1.

TABLE 2.1. MAIN STAKEHOLDERS

Stakeholders

Regulators (government agencies)

Industry (oil companies)

Society (public in general and interest groups)

Project Financing Agents (investors, banks, international development institutions)

Financial Assurance Agents (insurance and surety companies, banks, etc.)

Main Concerns

Financial and environmental liabilities Investment flow within the sector

Profitability Corporate image

Environmental protection Development

Investment returns Image

New business opportunities Risk reduction

Bonds may reduce liability risks by (1) providing financial incentive for contractual

compliance; (2) safeguarding government and taxpayers by attaining reasonable protection from

default at a minimum increase in project costs; and (3) protecting the environment from potential

harm resulting from failure to carry out proper closure operations in a timely fashion. Therefore,

22

oil companies wishing to explore and produce hydrocarbon resources would be required to post a

bond in advance equal to the best estimate to cover all closure costs.

As mentioned, setting the appropriate bond requirement may be one of the greatest

predicaments within a bonding system. It is not always possible to calculate the total monetary

value of complex non-market goods such as ecosystem functions and services, though many

methodologies currently exist to calculate partial values (for instance, COST A.t'JZA, et al., 1997).

Another predicament within bonding regimes is tax treatment. For most tax regimes,

closure obligations are ordinary and necessary expenses. In general, closure expenditures are tax

deductible only when services have been performed and payments have been made. The same

rule applies when progressive closure (the phased approach) is adopted.

Under most bonding regimes, there is no deduction available for companies allocating

funds as collateral until the company loses ownership of funds. However, if a company pays fees

or premiums to keep surety bonds or environmental insurance policies, expenditures would be

amortized over the period covered by the bond. Tbe basic rule is that only an ordinary and

necessary business expense is deductible; capital expenditure is not. Being contractually liable

for closure operations and emitting bonds (in anticipation) to guarantee such operations, does not

entitle companies to deduct cost of services before they are actually performed (FERREIRA and

SUSLICK, 2000).

Bonding Instruments

Traditionally, bonding instruments have been used to provide different forms of

guarantees as shown below (ROWE, 1987; JOHNSON, 1986; CORNWELL, 1997; MILLER,

2000): fidelity bonds (guarantee honesty); fiduciary bonds (guarantee the proper management of

assets); judicial bonds (guarantee the compliance with judicial decisions); and contractual bonds

(guarantee the fulfillment of contractual obligations). The category "Contractual Bonds"

includes several subcategories including: performance bonds; construction bonds; bid bonds;

service and materials bonds; advanced payment bonds; retention bonds; maintenance bonds;

transport bonds; government regulatory bonds; customs bonds; financial bonds; and license and

authorization bonds.

Within the Exploration and Production sector, two maJor bond categories can be

identified in terms of specific purpose: (1) financial bond, a bond that guarantees the payment of

23

a specific amount determined by the agency in case of noncompliance; and (2) performance

bond, a bond that guarantees the performance of a contractual obligation.

Bonds may be used several times within a single contract. Under some regrmes,

companies acquiring oil or gas leases are required to post a preliminary financial bond (a fixed

and relatively small bond) guaranteeing fmancial aspects of the lease contract (regular payments

of rents and royalties, civil penalties, fines, etc.). Usually, companies holding more than one

lease may opt for an "Areawide Bond", or "Blanket Bond", in which case, a single bond would

cover multiple leases.

In addition to financial bonds, some regulatory agencies require a performance bond,

which is usually based on the best-cost estimate for completing ex-post closure operations under

the established lease contract. Performance bonds serve individual projects and individual wells.

Multiple performance bonds may be found within a lease, but a single performance bond cannot

be used to cover multiple projects.

Performance bonds must be maintained until leases are terminated or transferred and until

closure obligations are satisfactorily met. If closure activities are being conducted concomitantly

during the life of the project, the phased approach, authorities may authorize proportional releases

ofthe bond.

A bond may be subject to forfeiture for different reasons: (I) if a well or installation has

been abandoned or temporarily closed without initiating required procedures; (2) if a company

fails to meet closure obligations in accordance with the approved plan; or (3) if a company fails

to maintain the amount bonded.

Financial instruments used to meet financial or performance bonding requirements may

come in several forms with unique attributes and requirements: some are the pledged assets of a

company (cash, securities, real estate, escrow accounts, salvage, etc.); others represent a

guarantee for a company's performance, fulfillment of obligations (surety bonds), or the

transferring of potential financial liabilities to other agents (e.g. insurance policies); others are

securities issued by bonding or insurance companies, banks or other financial institutions; and

still others are instruments that indicate the deposit of cash (certificates of deposit) or the

existence of a line of credit (letters of credit) (BRYAN, 1998).

Definitions and descriptions of currently used bonding instruments can be found in the

following publications: BLM (1996), CORNWELL (1997), MILLER (1998), FERREIRA and

24

SUSLICK (2000), OSM (2000b), }..'WF (2000), UNICAMP/CEPETRO (2001), FERREIRA and

SUSLICK (2003a).

Some complexities are involved in assessmg bonding instruments: (1) a specific

instrument may be known by a variety of names; (2) a single instrument may comprise a number

of significant variations and still carry tbe same name; and (3) some instruments can be

personalized witb contractual clauses altering their behavior, but keeping the same name.

Bonding instruments are classified in several ways, but a comprehensive classification

that could systematically embrace most instruments was not found. Some authors use a general

"soft" and "hard" classification (i.e. MILLER, 1998). "Hard" for instruments that cause

significant direct costs5, and "soft" for instruments that cause less significant direct costs.

Despite less significant direct costs, soft instruments may cause some indirect costs, which may

include reduction of credit capacity and increase of loan costs. Table 2.2 shows some fmancial

tools currently being used as bonding instruments to provide guarantee for end-of-leasing and

reclamation operations. This classification was designed to facilitate the systematic evaluation

and optimum applicability of each instrument.

TABLE 2.2. INSTRUMENT OPTIONS

2.4. DECISION MODEL

Short Name SURE PIACC PPACC LOC SELF IGS RE INSP POOL SFUND

Bonding Instrument Option Corporate Surety Bond Paid-in Cash Collateral Account Periodic Payment Collateral Account Letter of Credit Self Bond Investtnent Grade Security Bond Real Estate Collateral Bond Insurance Policy Bond Pool Guarantee Fund Designated State Fund

This model is an attempt to explain tbe current instrument choice by both regulators and

industry. It is also intended to systematize the decision-making process to assist in the selection

an optimum portfolio of bonding instruments. Such portfolio should offer, at same time,

adequate protection for regulators and an acceptable level of cost and flexibility for the industry.

5 Direct costs usually refer to opportunity costs and liquidity constraints caused by the allocation of large amounts of money at "startup".

25

Due to public pressure, regulators must impose bonding requirements; however, such

requirements generate significant negative impacts on the industry, which in turn, demands

flexibility. Regulators must respond in order to keep the market competitive and maintain the

investment flow in the sector. Closing the cycle, some of the flexibility allowed may increase the

risk for regulators, triggering further pressure from taxpayers and interest groups, as

demonstrated in Figure 2.3.

For this comparison exercise, this paper simulates the application often different financial

instruments identified by FERREIRA and SUSLICK (2001) that are commonly used in the oil

and mining sectors: Corporate surety bonds, paid-in cash collateral accounts, periodic payment

collateral accounts, letters of credit, self bonds, investment grade security bonds, real estate

collateral bond, pool guarantee funds, designated state funds. These instruments were chosen

based on a study done for ANP where several forms of bonding instruments were being

considered to provide ex-post performance guarantee for petroleum projects

(UNICAMP/CEPETRO, 2001). Currently, ANP requires financial bonds for the bidding process,

where letters of credit and cash are accepted. Studies are on the way aimed at establishing sound

performance bond requirements for all phases of Brazilian upstream petroleum projects. Among

instruments being studied are collateral cash (paid-in and leasing specific accounts), ex-post

insurance policies, and letters of credit.

The methodology used in this process was the identification of the most significant

attributes according to the perspective of key stakeholders. In addition, a questionnaire6 was

prepared and sent to a number of bond specialists who were asked to rank several bonding

instruments under several categories (attributes), according to their own experience. On

Appendix 1, on the questionnaire table, the left column indicates some of the instruments used to

guarantee or fund ex-post end-of-leasing, closure and reclamation obligations. The top row

identifies some of the characteristics of these instruments. Based on the specialist's own

6 This figure was not included in the original published paper. The information provided in this questionnaire was gathered in meetings with bond specialists from regulatory agencies, industry, financial institutions, and academia, all based on personal experiences with different financial assurance instruments. Regulatory agencies allow different fmancial instruments based on their own experiences, which oftentimes are not well documented in the academic literature. The information gathered in this questionnaire helped in the development of models that may assist in the decision-making process, anticipating economic impacts of different fmancial assurance instruments on regulators (regulatory cost, flow of investment, etc.) and on the industry (cost of money, cost of opportunity, tax treatment, etc.).

26

experience and judgment, he/she was asked score each instrument in the following manner: "5"

most favorable through "I" least favorable.

ENVIRONMENTAL LIABILITY

Impact on Agency

• Lower liquidity

BONDING REQUIREMENTS

• Difficulty in collecting the bond

• Feesltax • Premiums • Up-front capital • Liquidity constraints ,.; Opportunity costs

• H.igher credit costs • Less loan availability ,_ "'

o ... Wfl) a:o co

FINANCIAL WEIGHT • Higher monitoring costs •' :Lower incetive level FLEXIBILITY ·~ Reduction of system effectivenes;~ • Higher default risk •.• Higher risk of litigious battles

Impact on Industry

Figure 2.3. The dynamics of the bonding cycle: due to public pressure, bonding requirements are adopted. Bonds cause direct and indirect economic impacts on the industry, which pressures for flexibility. Flexibility may increase liability risk, forcing regulators to review requirements.

Although subjective, personal experiences of bonding professionals have been particularly

helpful to explain the current behavior and trends of regulatory systems. This process has also

provided data for the decision model explained below.

The Multiple Criteria Decision Analysis (MCDA) was used to balance the conflicting

objectives in the decision model. The main steps can be defined as follows according to

HWANG and YOON (1981), STAR and ZELENY (1977), and KEENEY (1992): (1) definition

of the main problem; (2) definition of the main attributes/criteria; (3) establishment of the relative

importance of each criteria; (4) identification of a set of available alternatives; (5) performance

assessment of all alternatives according to each criteria; and ( 6) selection of best alternatives.

This model was developed using the STELLA® software (Figure 2.4). Appendix D provides

some conceptual information about economic modeling, decision models, forecasting, and about

the Stella modeling tool. Appendix D also displays some of the mapping levels for this modef.

Which of the identified financial instruments (Table 2.4) are more likely to be accepted as

bonding tools for both regulators and the industry? In order to identify the instrument with the

highest performance, a process consisting of three parts must be undertaken: part 1, definition of

a preferable instrument alternative for regulators; part 2, definition of a preferable instrument

alternative for the industry; and part 3, cross-evaluation of results from parts one and two, and the

identification of a consensual best alternative.

TABLE 2.4. INSTRUMENTS AND PROPOSED CLASSIFICATION

PROPOSED CLASSIFICATION

Credit Guarantees

Negotiable

Collateral

Non-Negotiable

Self Guarantees

Liability Transfer

Risk Spreading Consortiums (for low-rating participants)

Risk Spreading Special Funds (for all participants)

INSTRUMENTS

Corporate Surety Bonds

Certificates of Deposit, Cash Equivalents, Government-Issued Treasury Securities (T-bonds, Investment Grade Securities, etc.)

Letters of Credit, Real Estate, Salvage, Cash Accounts, Escrow Accounts, Paid-In Trust Funds, Trust Funds with Periodic Payments, Standby Trust Funds, External Sinking Funds, Lines of Credit Bank, etc.

Balance Sheet Tests, Corporate Guarantees, Third-party Guarantees, SetAside Revenues and Self-Funding through Financial Reserves

Environmental Insurance, Finite Insurance, Life Insurance, Annuities

Pool Bonds

State Funds

Regulators and industry view the identified attributes with different degrees of importance

(weight) (Table 2.5). A choice of a certain instruntent may be appealing for regulators, but may

be severely opposed by the industry. In addition, the degree of flexibility demanded by the

industry may pose unacceptable risks to regulators. Costs to meet technical and bonding

requirements for closure obligations will impact companies differently. Usually large and

7 Infonnation and illustrations provided in Appendix D were not included in the original publication of this article.

28

financially healthy companies are not significantly affected by bonding requirements, though

marginal projects operated by any company (large or small) may be severely impacted. Small

companies operating small and marginal fields tend to be the most affected parties.

Figure 2.4. Diagram of the Stella Model, including the steps of the decision model: Ung. U,nd and Uwn.•·

A comprehensive set of objectives that reflect all concerns relevant to the decision

problem are defined at this point (definition of the main attributes). Regulators and the industry

do not share the same priorities, but, at same time, do not necessarily have conflicting interests.

Regulators are primarily interested in an efficient guarantee (protection), and the industry is

primarily interested in reducing economic impacts of bonding regulations (flexibility). The

measures for achieving these objectives are expressed in terms of key attributes identified by both

regulators and industry. Two sets of attributes were suggested reflecting the needs and

preoccupations of key stakeholders. Each set contains seven attributes. As illustrated in Table

2.5, the degree to which objectives are met as measured by the attributes is the basis for

comparing the sets of bond alternatives: Xreg = {xJ,X2, ... ,x7}; Xnd = {x8,X9, ... ,xJ4}.

The decision maker's perception with respect to the evaluation criteria must be

incorporated into the decision model. Each attribute has a certain degree of importance for a

specific decision maker. Therefore, a weight, which reflects the relative degree of importance of

criteria, is assigned to all evaluation attributes, as shown on Table 2.6. The derivation of weights

is a central step in eliciting the decision maker's preference. Weights reflect the preferences of

key stakeholders and hence depend on the choice of individuals. The importance of the attribute

x, could be specified by the weight w,, where the sum of each set of weights should be equal to 1

(one), as shown below:

7

I w' = 1 i"" 1

14

L w i = I i = 8

{ ' ' ' .I Wcons= W J, W ], ... , W f4f,

14

L w; = I i = 1

TABLE 2.5. ATTRIBUTES/CRITERIA

Rank X,., Short Name Regulator Perspective

7 X 1 LIQUIDITY Level of liquidity offered by the instrument in case of bond forfeit 6 X2 RISK Overall risk offered by the instrument 5 X3 COLLECTION Level of difficulty in collecting funds in case of bond forfeit 4 X4 INDIMP Regulator's concern with impact of instrument on the industry 3 X5 MONITORING Level of monitoring required in order to ensure instrument integrity

2 Level of incentive for contractual compliance offered by the

X6 INCENTNE instrument

1 X7 ELIMINATOR Does the instrument target primarily risky parties? Xind Industry Perspective

7 X 8 DIRECT Level of liquidity constraints and opportunity costs (Direct Costs)

6 X 9 FLEXIBILITY Overall flexibility offered by the instrument

5 X 10 FISCAL Level of fiscal advantages offered by the instrument

4 Xu WAYOUT Level of opportunity for an easy way out (legal, etc.) 3 X12 MONEY Level of money value protection for allocated funds offered

2 X13 INDIRECT Impact on credit and loan capacity (Indirect Impact)

1 Xu ACQUISITIONLevel of difficulty in instrument acquisition (underwriting process)

0.225 0.113 0.200 0.100 0.175 0.088 0.125 0.063 0.100 0.050

0.100 0.050

0.075 0.038 Total 0.500 0.275 0.138 0.200 0.100 0.175 0.088 0.150 0.075 0.100 0.050 0.050 0.025 0.050 0.025

Total 0.500

In order to assess all alternatives according to each attribute, a finite set of possible bond

options Aj={A~oAJ, ... ,A1o} is provided, as indicated in Table 2.2. This selection corresponds to the

group of most common financial instruments currently being used as bonding instruments in the

30

United States, Canada, and the UK. The process of evaluating the bond alternatives is based on

the value structure and related to the set of evaluation criteria.

TABLE 2.6. MATRIX XIJ: PERFORMA.l'oiCE OF BONDING ALTERNATIVES ON ATTRIBUTES"

Options Regulators Industry

XI x, x, x4 x, x, x, x, x, x/0 Xu xl2 Xu Xu AI SURE 4 5 4 4 5 5 4 5 4 5 1 1 4 1 A, PIACC 5 5 5 1 3 5 2 I I I I 3 4 4 A, PPACC 4 4 4 3 2 4 2 2 3 I I 3 4 4 A4 LOC 3 2 2 4 2 3 3 3 3 4 3 3 2 2 As SELF I I I 5 I I 3 5 5 I 5 I I 3 A, IGS 3 4 4 2 4 5 2 I I 2 I 4 4 4 A, RE I I I 5 I 2 I 5 4 2 5 I 2 5 A, INSP 4 2 2 4 2 2 2 4 4 5 3 I 5 3 A, POOL 3 I 2 4 I I I 3 4 I 3 I 4 5

Aw SFUND 3 2 3 3 2 I I 3 4 I 2 I 4 4

a Scores: (1) Least Favorable through (5) Most Favorable.

This process is intended to specify the performance of each alternative for every

evaluation criteria, allowing the identification of the best options. The performance of the bond

alternative Aj on attribute x; is indicated by xu. The values xu reflect the performance of

alternative Aj according to the criteria x;. Thus, an alternative is completely specified by its

performance score profile, as seen on Table 2.6. These scores also reflect the personal opinion of

key stakeholders from the industry, regulatory agencies, financial institutions and members of the

academia involved in the research of bonding mechanisms.

A decision-making rule provides an ordering of all bond alternatives according to their

performance with respect to the set of attributes. Choosing the most favorable bonding

instruments depends on the selection of the best outcome and the identification of the decision

alternative yielding this outcome. The performance of alternative Aj on the set of attributes

(x1,x2, .. xn) is associated with vector (x1j,X2j···Xnj) where a component of the vector xu gives the

numerical value of the performance of alternative Aj on criteria x;.

The multiattribute value function provides an integrated performance score for each bond

alternative taking into account all attributes. In the simplest case, value functions can be

combined with an additive weighed. Thus the overall value attached to a bond alternative is the

weighted sum of its attribute values: v(aj) = WJXIj + w2x2j + ... WnXnj· The components w 1,

w2, ... , wn are the weights which indicate the overall importance of each attribute. Since the current

31

problem involves three sub-problems, three different functions will provide the means for the

selection of the best alternatives for regulators, the industry, and for a consensual decision. The

three parts of the performance evaluation are shown below (Equations 1, 2 and 3):

a. Performance of bond alternative GJ for regulators:

7

uReg(a) = L w1xu i=l

b. Performance of bond alternative aJ for industry:

14

u1nd(a) = L w1xu i=8

c. Consensus for decision rule:

2.5. RESULTS AND DISCUSSION:

(1)

(2)

(3)

Table 2.7 indicates the results of the decision rule (Equations 1, 2 and 3). Colurrm II and

I indicate the final scores for the preferences of regulators and industry, respectively, UReg and

U1nd· Colurrm III results from the sum of colurrms II and I (Ucons)· Higher scores indicate

instruments with agreeable feedback from both parties. Colurrm IV indicates the positive

difference between colurrms I and II (!Liul). High Ucons values must be compared against l.dul values, which indicate high degree of antagonism between the two parties. The combination high

Ucons and low !Liul indicates the preferable scenario, where the instrument encounters less

resistance from both regulators and the industry, allowing a smoother implementation of bonding

requirements.

TABLE 2.7. TOTAL UTILITY

I II III IV Instruments

(Consensus) ltl.ul a (Regulators) (Industry)

AI SURE 2.200 1.775 3.975 0.425

A2 PIACC 2.038 0.750 2.788 1.288

A3 PPACC 1.763 1.088 2.850 0.675 A, LOC 1.325 1.538 2.863 0.213

As SELF 0.825 1.800 2.625 0.975

A• IGS 1.738 0.888 2.625 0.850 A, RE 0.800 1.863 2.663 1.063 A, INSP 1.350 1.863 3.213 0.513 Ag POOL 1.000 1.400 2.400 OAOO

A1o SFUND 1.175 1.300 2.475 0.125 a Llu is the difference between columns I and IL

32

Preliminary simulations suggest that surety bonds allow the highest Ucons· These results

are in agreement with actual bonding regimes. Insurance policies also reach high scores,

however, in actual scenarios; insurance policies are not well accepted by some regulators. It is

claimed that insurance policies simply transfer liabilities from producers to third party insurers

without generating reasonable incentives for compliance. In fact, agents from the insurance

sector agree that insurance policies provide an easier way out for lessees when compared to

surety bonds. Letters of credit also reach high Ucons values, but are not welcomed by some

regulators who claim that the instrument is as good as its issuer.

A set of new parameters should be included in the model in order to account for these

discrepancies. In addition, since the preference of regulators overcomes the preference of the

industry, a factor should be generated to account for this gain allowing a more realistic scenario.

When stakeholders are analyzed separately, the simulations yield a more realistic set of

outputs. According to the proposed model, the industry shows preference for insurance policies,

self and surety bonds. The same model indicates that regulators tend towards surety bonds and

cash collateral accounts.

2.6. CONCLUSIONS

In the oil sector, bonds indenmify authorities against failure to comply with lease

contractual obligations, safeguarding agencies against technical and financial failure, and

premature or unplanned closure. Under an ideal bonding regime, the financial risk is shifted from

the agency to the lessees. By internalizing ex-post damages and no compliance costs, oil

companies are motivated to monitor the consequences of their decisions throughout the project.

In case of default, funds necessary to complete all closure obligations would be promptly

available avoiding complicated and costly legal processes.

Though a hybrid of market mechanisms and command and control regulations, bonds are

also likely to achieve noncompliance protection objectives far more cost efficiently than non

market regulations. Bonds are best suited to cover ex -post environmental damages. The main

factors include cost assessment and duration of mitigating operations. Some complications are

expected in the near future as emerging issues are further considered. Preliminary results from

the simulation model indicate that the surety bond is the most preferable financial instrument

among regulators and the industry.

33

CHAPTER III- DECOMMISSIONING

How to guarantee that oil and gas leasing areas will be returned in similar preexisting

environmental conditions? Answer: establishing of sound ex-post requirements, including the

decommissioning of offShore installations.

In this chapter, some of the essential issues of offshore decommissioning are addressed.

The most prevalent issues cope with potential impacts of decommissioning expenditures. The

complexity of the theme increases due to the potential combination of:

• Installation type;

• Removal and disposal options; and

• A wide variety of settings.

In this chapter, the author does not attempt to discuss all these issues, but instead, defmes

key parameters and offers a systematic approach for addressing decommissioning costs.

3.1. END-OF-LEASING OBLIGATIONS AND PLATFORM DECOMMISSIONING

Ex-post (or end-of-leasing) obligations involve different activities including: engineering

analysis and planning; permitting and regulatory compliance; platform preparation; plugging,

capping and abandonment of wells; conductor removal; mobilization and demobilization;

platform and structural removal; pipeline and power cable decommissioning; transportation and

disposal; and site clearance and verification (NPD, 1993; UNEP and E&P FORUM, 1997; GAO,

1999; TOPE, 1999; MMS, 1999a; FERREIRA, 1999). Among the main objectives of ex-post

requirements in the upstream offshore sector are: isolate subsurface contaminations sources,

guarantee conditions of health and safety, and, if at all possible, return disturbed areas to their

pristine conditions.

Although embodying different meanings, the terms abandonment and decommissioning

are often used interchangeably. Both terms are also frequently used to designate the entire chain

of ex-post activities. Technically, the ex-post process includes several activities, including

abandonment and decommissioning operations. Decommissioning has been defined by ANON

(1999) as the activities related to bringing a platform from an operating condition to a cold,

34

hydrocarbon free condition (but excluding activities related to removal or other methods of

disposal). The same author defmes disposal as the process and/or agreement that brings an

installation to its final destination( s) (end-points), where it is reused, recycled, or deposited.

Most commonly, the term abandonment is used to denote the plugging and capping of a

specific well and the term decommissioning, which refers to the facility itself, designates the

process consisting of all activities involved in the removal and disposal of an offshore installation

(the term also applies to pipelines). The term abandonment seems to imply a "politically

incorrect" attitude for plugging and capping operations. The general public can easily

misinterpret this term as implying a negligent abandonment. Both Norway and UK authorities

have been using the term cessation to account for the entire end-of-leasing process (all ex-post

activities). Henceforth, because of references and some citations, the terms decommissioning,

abandonment, cessation, reclamation, closure, and end-of-leasing process may be used

interchangeably to indicate ex-post obligations.

Ex-post activities are identified and described bellow (from TY AGI, 1998; MMS, 1999b;

FERREIRA, 1999; GARLAND, 2000b):

1. Residual Value Appraisal: The starting point of the decommissioning process is a residual

value appraisal.

2. Engineering and Planning: When decommissioning has been firmly decided, pre-project

can start with the analysis of a huge data collection including installations, waste, etc. This

phase usually begins two to three years before production ceases. Within this phase, several

activities may take place including contractual review, engineering analyses, contracting, and

operational planning. Planning decommissioning operations ahead of time may significantly

reduce ex -post costs. Since the availability of expertise and appropriate equipment is limited,

early planning may be crucial. For example, the Norwegian legislation requires the

submission of a decommissioning plan 2 to 5 years before the license expires, or when an

installation or pipeline becomes redundant.

3. Permitting and Regulatory Compliance: This phase includes analysis of legal constraints,

contractual obligations, implicit obligations (meeting governmental and stakeholders

35

expectations), finances, fiscal regime, and safety and environmental issues. In addition, this

phase involves activities such as obtaining permits and making installations and all future

operations comply with local, State, and Federal rules. Usually during this phase,

environmental consultancy firms are hired to assess environmental impacts. Companies may

have to provide compensation to commercial fishing companies that are precluded from

fishing in areas where decommissioning activities are taking place. Several issues rise

regarding commercial fishing (i.e. exclusion areas, sanctuaries, etc.). This theme has

attracted a passionate discussion between the oil and fishery industry, environmentalists, and

several NGOs (MMS, 1987; MMS 1997a; OSMUNDSEN and TVETERAS (2000);

SANCHIRICO, 2000; DAUTERIVE, 2000b).

4. Platform Preparation: Platform preparation, also known as safeout operations, involves

activities aimed at turning the installation safe and ready for dismantling, removal, transport,

and disposal. This phase also includes structure and equipment cleaning.

5. Well Plugging and Abandonment: Plugging all exploration8 and development wells,

isolating subsurface hydrocarbon sources from other subsurface, surface, and freshwater

aquifers zones, preventing contamination. This process involves placing a series of concrete

and mechanical plugs, and testing their pressure, integrity, and durability (TYAGI, 1998).

Following plugging, the well site must be cleared of all obstructions and cuttings. Wells can

be shut-in or temporarily abandoned. Production may be interrupted by technical or

economical reasons. If the interruption is only temporary, the well is shut-in, but if it is

permanent, the well must be plugged and abandoned. Shut-ins involve simply closing the

valves on the Christmas tree. Ifthe duration of the shut-in exceeds a predetermined allowable

period (usually one year), permanent abandonment will be required. Once a well is

permanently plugged and abandoned, it becomes mostly unfeasible to reach remammg

reserves through that well. The MMS has been using Satellite Radar hnagery to detect leaks

at abandoned wells on the US Outer Continental Shelf (MARTIN, 2000). Even though well

plugging and abandonment is considered one of the more sensitive ex -post activities within

8 Despite technological and research efforts, approximately 80% of all pioneer wells do not result in economic prospects. When a well does not indicate the presence of oil, it must be plugged and abandoned.

36

the decommissioning process, planning in advance may significantly reduce uncertainties

(FIELDS and MARTIN, 1997). In the GOM Region, well plugging and abandonment may

cost generally less than US$ 60,000/well and rule allow casing to be left in the hole bellow

4.57 meters and tubing can be left in the hole bellow 91.44 meters.

6. Conductor Removal: This process involves the severing, plugging, and offloading of casings.

These activities require the use of a platform crane.

7. Mobilization and Demobilization: It involves bringing a Heavy Lift Vessel (HL V) to the

project site and returning the vessel to its point of origin. When there are no vessels with the

capability to remove platforms within the productive area, the vessel has to be brought from

other areas (usually from the GOM or NS). Total mobilization and demobilization time may

vary greatly from the distances between locations (i.e. 100 to 200 days.).

8. Platform and Structural Removal: This process includes the removal of the topside (or

deck), and the removal of the platform (or structure). Pile severing denotes the method used

to separate the platform's components (explosives, mechanical means, abrasive technology,

or torches). Severing is currently a very controversial issue due to the potential danger posed

to marine animals. Most legal regimes require the complete removal of all offshore

installations. CULWELL (1997) and PASTHOFER (1997) discuss technical processes of

deck and jacket decommissioning.

9. Pipeline and Power Cable Decommissioning: Decommissioning of these components is a

very complex issue. Knowledge of gradual degradation is limited, since model calculations

may not be verified through observations. A rough estimate of total degradation period for

steel pipelines is 300-500 years9• Removal methods are mainly based on costly reversed

installation. Reuse experience for pipelines is limited and, under most regimes, in order to

obtain a pipeline license, a company must demonstrate that specifications and quality of the

material is adequate. Pipelines must be decommissioned in order to prevent seepage and to

minimize potential safety hazards for the environment, marine and human lives, and

9 Intact concrete caps may significantly delay degradation.

37

navigation activities. Submarine pipelines and cables are located at a variety of settings.

Removal and disposal options are not included in international conventions and national

authorities, which may decide on costly solutions, usually define the rules. Regardless of

available options, pipelines should be pigged and flushed until they are clean to avoid future

leakage. Some agencies (i.e. MMS) require pipelines to be cut at each end, filled with

seawater or inhibited water, and caped. Each end should be buried (O'CONNOR, 2000).

10. Transportation and Disposal: Process steel, marine growth, cement, mud, etc., are materials

that must be removed and properly disposed of. There are three main disposal approaches:

(I) refurbish for reuse, (2) scrap and recycle, and (3) disposal in designated landfills.

Opportunities for refurbishing and reusing facilities depend of several corroborating factors

such as structural integrity, additional project developments in the region, matching technical

parameters, etc. Transportation and disposal of these materials can be costly. These and

other options will be further discussed in this chapter.

11. Site Clearance and Verification: All obstructions must be cleared from the site. This process

may require dragging a trawl, diver search around the well bore, and even seafloor scanning.

These activities will ensure that the site is free of obstructions (i.e. sunken helicopters have

been found on the seafloor around platforms in the GOM).

3.2. THE DEVELOPMENT OF THE LEGAL FRAMEWORK

For being part of the global commons, oceans must be contemplated beyond domestic

interests and expectations. Offshore ex -post requirements (including decommissioning

operations) must follow the same rationale. International conventions and guidelines are

primarily aimed at establishing legal trends, influencing national legislation, and allowing sound

environmental attitudes where a domestic legal framework does not exist. Additionally,

international laws impose accountability and constraints on national governments. National

governments then legislate in conformity with the international legal framework. Before 1995,

both international and domestic decommissioning requirements were flexible to some extent and

allowed analysis on a case-by-case basis (UNEP and E&P FORUM, 1997; FERREIRA and

SUSLICK, 1999, 2000). However, since the Brent Spar episode in 1995, interest groups have

38

been pressuring for changes m the regulatory framework by requesting the elimination of the

case-by-case approach and calling for complete decommissioning (total removal) in all

circumstances. Figure 3.1 summarizes this session.

EU Moratorium2

~ ActiYe!

Decommissioning ~

... Future' I

...

1947 First platform out of sight ofland

1958 Geneva Convention

1972

1973

UN Conference on man & the Environment London Dumping Convention Oslo Convention Regional Seas Program International Convention for the Prevention of Pollution from Ships (MARPOL)

1982 United Nations Convention on the Law of the Sea (UNCLOS)

1989 IMO Guidelines and Standards on Removal of Platforms

1991

1992

Oslo Commission adopts Guidelines on Platform Disposal Oslo & Paris Conventions amalgamate

Convention for the Protection of the Marine Environment of the NE Atlantic 1994 (OSPAR)

1995 ····················································································· Brent Soar UK DTI Guidelines

1996

1998

1999

2003

Law of Sea Convention enters into force

LC 72 States agree new protocol OSP AR Portugal- Ban on sea disposal4

DTI Re-issued Guidelines

Figure 3.1. Main International and Regional regulations, treats and guidelines. 'Operations under the Guidelines of the UN International Maritime Organization. 2UK and Norway did not sign the moratorium and continued decommissioning activities following !MO. 'New issues may include drill cuttings. pipelines, and NORMs. 4Except on concrete, damaged and footing of jackets > 10,000 tons.

39

Probably due to the vague regulatory language employed in international conventions and

guidelines, there is still considerable confusion in matters of interpretation. Different

stakeholders present convincing arguments for their divergent demands, and it is not difficult to

find contradictions and opposing views in different international conventions and guidelines. It is

practically impossible to strictly observe all requirements simultaneously.

There are other sources of predicaments. Since international legal provisions cannot

specify ex -post procedures for internal waters, territorial seas, etc., guidelines and conventions

can only be recommendatory in nature, and the nation is sovereign in regulating and enforcing

their offshore oil projects. Usually, national authorities abide by international provisions.

Nevertheless, due to high ex-post costs, in situations where a government has sovereignty over an

area and public opinion is not a crucial parameter, authorities may disregard international

conventions and guidelines.

There are several international conventions and treaties dealing with offshore

decommissioning. The most important are:

1. The 1958 Geneva Convention on the Continental Shelf: The official implementation of the

Geneva Convention carne only in 1964 when 56 countries signed it. The main provision of

this convention, Article 5( 5), calls for complete removal of offshore installations but does not

mention platform disposal. There is a vast literature record on the interpretation of this

article, either favoring or going against the total removal concept. Great part of the industry

favors the argument that the 1958 convention is no longer applicable, but the public and other

key stakeholders have a different opinion.

2. The 1972 Convention on the Prevention of Marine Pollution by Dumping of Wastes and

other Matter (the London Convention): An international treaty signed by 77 nations

presenting provisions for all marine areas, except internal waters. The most important

provision of this Convention is found in the Article ill (l)(a), which defines "dumping" as

"any deliberate disposal at sea of vessels, aircraft, platforms or other man-made structures".

3. The 1982 United Nations Convention on the Law of the Sea (UNCLOS): The UNCLOS

was ratified by 127 nations and came into force in 1994. It ensures acceptance of coastal

40

state control over offshore resources (sovereignty), while preserving freedoms of navigation

and overflight. Article 60(3) permits the interpretation in favor of partial removal by stating:

"Any installations or structures which are abandoned or disused shall be removed to ensure

safety of navigation, taking into account any generally accepted international standards

established in this regard by the competent international organization. Such removal shall

also have due regard to fishing, the protection of the marine environment and the rights and

duties of other States. Appropriate publicity shall be given to the depth, position and

dimensions of any installations or structures not entirely removed". As it was with the 1958

Geneva Convention, dispute over the interpretation of this article has erupted. The German

interpretation is that the only way to ensure safety and environmental protection is to

completely remove offshore installations. The British interpretation is that complete/total

removal is contrary to the provisions of Article 60(3). The US interpretation accepts the total

removal interpretation but admits an "occasional limited exception" (PICTON

TURBERVILL, 1998).

4. The 1989 International Maritime Organization Guidelines and Standards for the Removal

of Offshore Installations and Structures on the Continental Shelf (the IMO Guidelines):

The Il\1:0 Guidelines and Standards, which is basically an interpretation for the 1982

UNCLOS and provides narrow exceptions to the policy of complete removal, sets the

following standards for the decommissioning of offshore oil and gas installations (Il\1:0,

1996):

• Installations weighting less than 4,000 tons, located at places where the water depth

is less than 100 m, must be completely removed from the site.

• Installations located at water depths greater than 100 m must be either totally or

partially removed to a depth allowing an unobstructed water colunm of 55 m above

the remaining portions of the installation in order to avoid navigational hazards.

• Total removal will not be required in the following circumstances: technical

unfeasibility, unacceptable human or environmental risk involved in the total

removal operations, and extreme costs.

• All installations (after January 1, 1998) must be designed and built so that their

complete removal is feasible ( decommissionable structures).

41

• A structure may be left partially or entirely in place if there is a justifiable and

permitted new use or if the structure can be left in place without causing

unjustifiable interference with other users of the sea.

5. The 1996 Protocol to the London Convention: This protocol allows the dumping of offshore

installations, consistent with guidelines being developed in the Scientific Group.

6. The 1997 Waste Assessment Framework (Scientific Group- May 1997): It provides draft

guidelines for decommissioning, a framework for governmental decision-making for the

issuance of permits to dump using a case-by-case approach, and recommends the

consideration of environmental effects.

Currently the London Convention governs the disposal of waste and other material. This

convention specifically addresses the disposal of offshore installations. Countries with no

national decommissioning regulations generally proceed in accordance with IMO guidelines.

Many producing areas are shared by different neighboring nations, as it is the case of the

North Sea oil and gas province. In such cases, regional conventions are of great importance.

Until 1998, as part of the UN Regional Seas Program, which began in the early 1970's, there

were 15 regional conventions controlling pollution of the marine enviromnent (GRIFFIN,

1998c).

The Baltic Sea regional legal regime requires total removal for all offshore installations.

Countries included in Northeastern Atlantic conventions may be going towards a complete ban

on sea disposal. Greenpeace pushes for an international ban on partial decommissioning

(GREENPEACE, 1998). South Pacific Conventions allows dumping by permit after

consideration by other affected parties. Guidelines are being developed for offshore petroleum

activities in the Arctic Region. Conventions in the Asia-Pacific Region tend to facilitate private

public cooperation (W ALK.ER, 1998). The following is a brief description of some key regional

agreements:

1. The 1972 Convention on the Prevention of Marine Pollution by Dumping from Ship and

Aircraft (the Oslo Convention): This regional agreement comprises the North East Atlantic,

42

the North Sea and portions of the Arctic Ocean. It prohibits dumping of materials from ships,

aircraft, and platforms.

2. The 1974 Convention on the Prevention of Marine Pollution from Land Based Sources

(the Paris Convention): This regional convention controls discharges into the North East

Atlantic.

3. The 1991 Oslo Commission Guidelines for the Disposal of Installations at Sea (the

OSCOM Guidelines): The OSCOM Guidelines is aimed at supplementing the 1989 IMO

Guidelines by recognizing other alternatives for removal (partial removal). It also establishes

a permit system which yields the evaluation of decommissioning project proposals in a case

by-case basis, allowing the consideration of the "leaving-in-place" option, complete or partial

removal for reuse, scrapping on land, disposal at sea (dumping) or elsewhere.

4. The 1992 Convention for the Protection of the Marine Environment in the North East

Atlantic (the OSPAR Convention): The OSPAR was adopted by the Oslo and Paris

Commission in 1992. It establishes that no offshore structure, including pipelines, can be

dumped, left wholly or partially in place at sea unless the competent authority, which will

analyze it on a case-by-case basis, issues a special permit.

5. The 1995 OSCOM Moratorium: After the Brent Spar episode, a ban on sea disposal was

imposed at the Northeast Atlantic. The UK and Norway governments did not sign this

moratorium and proceeded with decommissioning operations.

6. The Barcelona Convention: This regional convention controls pollution on the

Mediterranean Sea and requires removal of offshore installations, but allows the conversion

of platforms to new alternative uses (GRIFFIN, 1998b; RAMPOLLI and FASCI, 1997).

7. The Kuwait Protocol: This protocol controls pollution in the Persian Gulf and requires

removal of offshore installations.

43

8. OSPAR Effective February 9, 1999: Anything installed after February 9, 1999, must be

taken to shore unless it is reused or derogated for safety, environment, technical, or economic

reasons. There is no date set for concrete based platforms, but its use is discouraged. This

convention also bans sea disposal but provides exceptions (concrete, bottom bay over 10,000

tons, and matters of safety, environment, technology, and economics).

9. OSPAR Review in 2003: In the 2003-scheduled OSPAR Review, the subjects to be

considered are: drill cuttings, hazardous chemicals, produced water, among others.

Despite the effort of international organizations and the availability of regional and

international legal models, only few countries have developed their own domestic offshore

decommissioning legislation. Most countries provide only superficial or no provisions for

decommissioning procedures. Presently, several developing countries have established or are in

the process of establishing their own offshore ex-post rules (i.e. Brazil, Indonesia, Belize,

Venezuela, Australia, etc.).

Thus far, Australia has minimal decommissioning activity. A FPSO off Western

Australia, the Sk:ua, was decommissioned in 1999 and all equipment and pipelines were

recovered and reused at Elang/Kakatua. In 1994, the Talisman, also a FPSO, was

decommissioned in Western Australia. The Talisman was sent to Singapore, and all other

facilities were removed. The Australian legislation has adopted specific and general

requirements. Specific requirements address the task of removing or abandoning facilities:

Environmental Protection (Sea Dumping) Act, 1981, that implements the 1972 London

Convention, the 1972 London Convention guidelines, and the 1988 !MO. General requirements

address the abandonment or removal approvals process: the 1967 Petroleum Act (Submerged

Lands), and the 1999 Environmental Protection and Biodiversity Conservation Act. The Federal

Government is in the process of developing guidelines for decommissioning approvals process

(SIIII\i'NERS, 2000).

Canada's offshore sector is still in its infancy. Production has been initiated in the early

1990's, and only now few projects are reaching their maturity and exhaustion stages.

Decommissioning has been addressed in Canadian legislation and early in project lives, but it is

only now becoming a focal issue within government and industry (ABRAHAM, 2001).

44

Brazil has passed the Law number 9.966 of April 20, 2000 that deals with the prevention,

control, and enforcement of pollution caused by oil spills and other polluting and hazardous

substances in waters under national jurisdiction (DOU, 2000). This Law is based on the 1973

International Convention for the Prevention of Pollution from Ships as modified by the related

Protocol of 1978 known as Marpol 73/78. In addition, Law no. 6,938/81 (National

Environmental Policy) has created a national database system, the National Environmental

Information System (SINAMA), and the National Environmental Council (CONAMA) (RUIVO

and MOROOKA, 2001). The CONAMA is responsible for the environmental licensing process

required for all E&P activities. The Brazilian Environmental and Nonrenewable Natural

Resources Institute (IBAMA) is responsible for processing E&P environmental licenses for all

offshore petroleum projects. In 2000, ANP and IBAMA initiated a review of procedures aimed

at harmonizing the licensing process with environmental requirements. Nevertheless, specific

decommissioning regulations are yet to be developed.

Most national provisions are derived from international conventions and guidelines.

Local legislators work on establishing requirements that may satisfY domestic and international

environmental demands, and, at the same time, that are economically feasible. The main

concerns are the public demand for environmental preservation and government interest in

maintaining the flow of investments in the sector.

Regulators may vary proposed rules according to their capacity to review and approve

decommissioning plans, and enforce ex-post requirements. For instance, bonding requirements

tend to motivate the development of alternative technologies. If authorities were to oversee

directly all decommissioning operations, including evaluate new technologies, the information

burden and enforcement expenditure would be excessive. By requiring total corporate liability

and transparency (allowing public information access), authorities may be freed of such burden.

Changes in international conventions and domestic legislation have a great impact in the

cash flow of oil companies. Solutions must take into consideration technical, environmental, and

economic parameters, avoiding unfounded and ineffective restrictive policies that can affect the

continuation of long-term investment commitments in the sector.

One of the issues being currently considered by regulators is the concern over the

financial capability of buyers; the exit of majors or transference of leases from large operating

companies to smaller ones. When leases are marginally funded, the risk of non-compliance

45

mcreases. One solution would be that both the original assignor of the lease and the new lease

owner would be co-responsible for ex-post compliance associated with the original facilities.

Regulatory trends points to some very complex issues including pipeline flushing and

decommissioning, shell mounds (drill cuttings, mud, covered by mussel shells), time limit

enforcement for decommissioning operations, tightening of bonding requirements to guarantee

decommissioning funding, ban on explosives, recycling, re-utilization (recommissioning), and

commercialization of redundant facilities.

For internal waters, the closest maritime zone to the land, including waters between shore

and Territorial Sea (bays, rivers, lakes, lagoons, channels, archipelagic waters, seabed and

subsoil), international treaties and conventions are only recommendatory in nature and the

discretion of the coastal nation is considerable. Therefore, costal nations are completely

sovereign in regulating the decommissioning of redundant offshore installations within their

internal waters.

3.3. HISTORICAL OVERVIEW

The first important international acknowledgement of potential problems related to the

abandonment of offshore installations occurred in the 1958 Geneva Convention on the

Continental Shelf The first offshore decommissioning record encountered in the literature comes

from GOM in 1973 (GRIFFIN, 1998a). The Phillips Petroleum (Norway) has conducted studies

of potential decommissioning costs in 1975 and 1979 (PHILLIPS, 1999b; NPD, 1999).

Although decommissioning operations have been occurring for almost 30 years (specially

in the GOM), arising interest on this issue was only triggered during the development of the

Brent Spar decommissioning episode (Figure 3.2). This notorious episode started in 1995 with

the Royal Dutch Shell's decision to dump a redundant buoy in the North Sea. Thirteen options

were reviewed and after four years of studies, Shell decided to sink Brent Spar in deep waters

(around 1,830 meters). The onshore disposal of the buoy was considered too risky, and would

cost 400% more than dumping it.

At that time, Greenpeace used the media very efficiently. As a result, protesters attacked

gas stations in Germany and a very effective boycott was launched (it spoiled 30% of retail in

Germany). At the same time, Greenpeace activists occupied Brent Spar. The aftermath of this

campaign was that the great majority of European Governments were against dumping Brent

46

Figure 3.2. Brent Spar and the stained Shell's logo (Shell, 1995; Greenpeace, 1995)

Ill c 0

iw+·············································································

~ .5 ... 0 10 +·················································································

'1:1:

Spar. Brent Spar was sent to Norway where it was

dismantled and disposed of on land10• The

decommissioning of Brent Spar cost Shell

approximately US$ 77.4 million, not including the

economic impacts of the boycott (FERREIRA,

1999). Greenpeace strategy was indeed successful;

a milestone in time was established and its

consequences changed the path of the industry

(GROVE-WHITE, 1997). It was the first large ex

post operation in the North Sea Province and there

were over 70 large facilities to be decommissioned

in the following years (Figure 3.3). Brent Spar set

an unsettling precedent for the oil industry and

several lessons can be learned from this event:

Figure 3.3. North Sea Decommissioning Timetable (GRIFFIN, 2000a).

10 The Shell Oil Company had to go far beyond regulatory requirements to satisfY public and interest groups demands. The buoy was completely removed, transported to shore, and cut into ring sections. Part ofthe rings was used in the construction of a pier in the Norwegian coast (SHELL, 1998).

47

• Shell should have trained a crisis management team to anticipate potential societal

problems and promptly act to prevent ex-post damages to its image.

• Shell should have invited to the decision-making process all interested stakeholders,

including the general public;

• People's emotional reactions should have been treated as a crucial parameter;

• Shell should have communicated with the public more efficiently and, before crisis

erupted, provided education on the subject to all key stakeholders, mainly the media;

• Compliance with all international, regional, and domestic policies might not

necessarily satisfy the expectations of public and interest groups. When oil companies are

pressured by public opinion, they will be compelled to surpass current regulations and

even scientific recommendations, despite significant economic impacts.

Brent Spar cannot be blamed alone for such abrupt public interest on decommissioning

activities. The first major round of important decommissioning operations involving large

installations was expected for the end of the 1990s and interest groups may have seen the Brent

Spar Buoy as an ideal opportunity to state their case. Besides, increasingly public involvement

had made government economics more transparent and decommissioning costs, which are

usually tax-deductible, became public. In addition, as mentioned, this chain of events coincided

with the climax of the international sustainable development agenda (NERC, 1996, 1998).

3.4. DECOMMISSIONING OFFSHORE INSTALLATIONS

According to MARTIN (2000), "all platforms are not created equal". Offshore platforms

can be designed for a variety of needs, environments, and purposes (drilling, production, storage,

utilities, accommodation, etc.). Parameters such as water depth, distance from shore,

environment setting, and climate, prescribe the appropriate type of installation and make them

unique and site-specific (GRIFFIN, 2000a). The most common types are: steel jacketed platform

for shallow waters; mini-jacket (for marginal-field development); concrete gravity structure; steel

gravity structure (jack-up); steel jacketed platform for deep waters; tension leg platform (TLP);

compliant tower; semi-submersible platform; spar buoy; and floating production system (FPSO,

FSO, etc.) (Figure 3.4).

48

The steel jacketed (frame-shaped) platform is the most common platform type comprising

approximately 80% to 95% of all installations in place worldwide. Steel jacket structures weight

between 400 and 77,000 tons, including both superstructure and substructure. Steel jackets are

usually installed in waters with depths ranging from 10 to 200 meters.

Gravity base platforms are typically used in depths ranging between 70 and 200 meters,

but there are exceptions. Their superstructures can weight from 11,000 to 54,000 tons and their

substructure between 130,000 and 800,000 tons (POREMSKI, 1998). According to NORSKE

SHELL EXPLORATION AND PRODUCTION (1999), the world's tallest gravity base concrete

production platform, the Troll A platform, is located at the giant Troll Field, Europe's largest

offshore gas field. Troll A's gravity base structure weights 656,000 tons. Its total height is 472

meters (from top to bottom) and its total weight is 1,050,000 tons. Troll A is located 65 km from

shore in 303 meters of water column. The construction contract including mechanical outfitting

was awarded to Norwegian Contractors in March of 1991. The value of the contract was US$

475.35 million (NORSKE SHELL EXPLORATION AND PRODUCTION, 1999). The platform

is sited 80 km NW of Bergen, Norway OCS (Figure 3.5).

The largest semi-submersible platform, the P-36, was operating at Campos Basin in Brazil

until it sunk in 2001 killing 11 Petrobras employees (Figure 3.6). It weighted 32,000 tons and

was 120 meters high. Two world records were expected to be broken with P-36: production

volume (180,000 bbl!day of oil and 7.2 million cubic meters/day of natural gas) and completion

in deep waters (1,360 meters). Twenty-one wells were connected to P-36 comprising 15% of the

total Brazilian production until 2000 (ANP, 2000b). Unfortunately, P-36 cannot be recovered,

recommissioned, or be used as an artificial reef. At the present depth, 1,360 meters, the

ecosystem cannot be improved by P-36's presence. Other legal issues have emerged from the

episode. A Norwegian insurance company has made an agreement with the family of most

victims in a much-criticized deal where each family should receive approximately US$ 29,000 (0

GLOBO, 2003). This episode should call the attention for issues related to accidental damages

and instruments that are more efficient and fair.

Usually, offshore installations are planned for approximately 20-year projects but most

platforms can have a functional life that ranges from 30 to 40 years. At the end of this period,

after production ends, unless the platform is reused in situ or relocated, it must be

49

decommissioned. The main predicament is that most offshore structures were not designed to be

removed.

The number of installations going into decommissioning varies greatly according to the

life of the reservoir, time of installation, oil price, and other economic factors, making it difficult

to forecast a precise decommissioning schedule. The present scenario is that many aging

offshore fields around the world, mainly in GOM and in the North Sea, are near the end of their

productive lives. Many of them have already economically depleted their resources

(COLEMAN, 1998). In the United States Outer Continental Shelf (OCS), platform

decommissioning rate is increasing and, in some instances, going beyond the installation rate.

Over 35% of all offshore projects in the US are over 25-year old (MMS, 1999a). According to

PERRY ill eta!. (1998), approximately 620 wells are plugged and abandoned every year in the

US. WATSON (1998) indicates that 120 to 150 p1atfonns are removed every year only in the

GOM. The Minerals Management Service (MMS) confinns this information and forecasts that

100 to 200 structures will be decommissioned each year (BUFFINGTON, 1996; MARTIN,

2000). Figure 3.7 shows GOM's average platform installations and removals from 1987 to 1999,

Figure 3.8 projects future GOM's decommissioning activities up until 2020, and Figure 3.9

indicates the average decommissioning cost per ton.

3.5. DECOMMISSIONING OPTIONS

Establishing a single decommissioning solution for all offshore installations would be

unrealistic. The variety of possible combinations of installations and settings, the number of

possible combinations of decommissioning options, and, most importantly, large amounts of

money involved, make this subject a very complex and politicized matter. Figure 3.10 indicates

the main removal and disposal options for offshore installations.

Most national legal provisions allow oil companies to suggest a decommissioning plan,

being the applicable authority responsible for making the final decision, accepting, rejecting, or

requiring modifications to the original plan. The decommissioning plan presented by a company

usually details all considered options stating the basis for the recommendation. Figure 3.11

indicates some detailed removal and disposal options for some offshore facilities and

components.

50

Figure 3.4. Platform types. (I) Steel jacketed platform (shallow water); (2) concrete gravity structure; (3) steel gravity structure; (4) floating production system; (5) steel jacketed platform (deep water); (6) compliant tower; and (7) tension leg platform (GRIFFIN, 2000a).

Figure 3.5. Artist's impression of the Troll A platform superimposed on a photograph of Paris (NORSKE SHELL EXPLORATION AND PRODUCTION. 1999).

51

Figure 3.6. Sinking Petrobras' P-36 (FOLHA ONLINE, 2001).

Under strict deconnnissioning rules, items located towards the bottom of the illustration

tend to be more complex and costly. Ex-post environmental remediation costs for these items are

expected to rise in the future due to new rules and more rigorous clean-up standards

(JOHNSTONE et al., 1995). Some items, such as concrete gravity, in addition to complex and

expensive operations, may pose serious safety risks. As mentioned, new guidelines and rules for

pipeline and drill cuttings removal and disposal are currently being discussed (CAMPBELL,

2000).

According to GRIFFIN ( 1998c ), only some 600 large installations, less than 10% of total

World platform population, have a greater potential to prompt major controversies. In order to

exemplify this controversy, PITTARD (1997) suggests that only around 3% of the word's

installations should be candidates for partial removal. The spotlight of the dispute is certainly

expected to be on large fixed platforms. Figure 3.12 depicts a comparative illustration of small

and large platforms.

The main argument used by interest groups to call for a ban on partial removal is the

potential environmental impact generated by this option. This position has been questioned by

the industry, which claims that environmental impacts resulting from different deconnnissioning

options are negligible. Structures are cleaned before they are deconnnissioned and little

environmental impact is expected from substructures. According to the industry, parameters such

as cost, safety of personnel involved, and technical practicability, should preponderate in the

decision-making process (UKOOA, 1995). As previously mentioned, the adoption of high cost

solutions offers only marginal or debatable environmental benefits.

Interest groups challenge industry's reasoning by evoking the Precautionary Principle:

"preventative measures are to be taken when there are reasonable grounds for concern that

substances or energy introduced, directly or indirectly, will bring about hazards to human health,

harm living resources and ecosystems, or interfere with other legitimate uses of the sea, even

when there is no conclusive evidence of a causal relationship between the inputs and the effects"

(GREEJ\'PEACE, 1995).

52

250

200 195

178 174 .,

E 153

~ 150 "' 0::: ... 119 0 ~ .. 100 ,Q

E :I z

50

0

87 88 89 90 91

122

92

179

93 Year

154

94

D Installations Ill Rem ovals

152

139 132 134

95 96 97 98 99

Figure 3. 7. GOM average platform installations and removals from 1987 to 1999 (source: MARTIN, 2000)

300

250

1/) 200 c 0

:;::; .!!!150

.!!! 1/) c

0 '*~:

100

50

-Future

o~---.----.----,----,---~,----.----r----r----.--

•.:~1-;

Figure 3.8. GOM's present and future decommissions (source: MARTIN, 2000)

53

1600 1480

1400

1200 ... "' 2. 1000 967

c 0 s 800 .. 0 667

0 760 1/)

J

.. 600 0 -(!) 400

653

495

200

0 1990 1991 1992 1993 1994 1995 1996

Cost I ton' 553 495 667 653 733 967 760

Year

Figure 3.9. GOM decommissioning cost per ton. Gross Cost Per Ton considers all decommissioning costs except well P&A dived by total facility weigbt, including jackets, piles, and topsides, based on 54 actual platform removals. Source: TW ACHTMAN SNYDER & BYRD, Inc., 1999).

I OFFSHORE INSTALLATIONS I ' I I

I TOPSIDES/UNITS I I SUBSTRUCTURE

I I I I

Usually taken Total Partial Remain in

to shore (reuse Removal Removal situ

or recycling) H Stand by

Deep water disposal - Emplacement Alternative (dumping site) or toppling use (in situ)

Reuse or alternative use 1-(i.e. artificial reefs)

Transported to shore: t-recycling or disposal as scrap

Figure 3.10. Decommissioning options and endpoints for topsides and substructures (sources: PRASTHOFER., 1998; UKOOA, 1995; ATHANASSOPOULOS et al., 1999 and ODCP, 1998).

54

OPTIONS 1 Piecesmall dismantle, onshore disposal 2 Modular dismantle, onshore disposal ... 3 Modular dismantle, strip onshore and dispose, stripped module to CS

TOPSIDES r 4 Modular dismantle, strip onshore and dispose, stripped module to reef 5 Modular dismantle, strip onsh:>re and dispose, stripped module to deep sea 6 Modular dismantle, strip offshore, deposit stripped in-situ, waste to land 7 Strip offshore, waste to land, topple stripped modules in-situ 8 Modular dismantle, strip offshore, deposit stripped on CS, waste to land 9 Modular dismantle, strip offshore, deposit stripped at reef, Waste to land 10 Modular dismantle, strip offshore, deposit stripped in deep sea, waste to land 11 Topple modules in-situ, no stripping 12 Modular dismantle, deposit unstripped at reef 13 Modular dismantle, deposit unstripped in deep sea

1 Tcpple in-situ in absence of cuttings 2 Topple in-situ in presence of cuttings

STEEL JACKET I 3 Partially remove and lay beside stump 4 Partially remove and deposit on CS 5 Partially remove and deposit at reef 6 Partially remove and deep sea dump 7 Partially remove, dismantle and dispose onshore 8 Totally remove in absence of cuttings and deposit on CS

• 9 Totally remove in absence of cuttings and deposit at reef 1J1 E-< 10 Totally remove in absence of cuttings and deep sea dump 1J1 11 Totally remove in absence of cuttings, dismantle and dispose onshore 0 12 Totally remove in presence of cuttings and deposit on CS u 13 Totally remove in presence of cuttings and deposit at reef

14 Totally remove in presence of cuttings and deep sea dump 15 Totally remove in presence of cuttings, dismantle and dispose onshore

1 Leave in-situ CONCRETE GRAVITY l 2 Refloat in absence of cuttings and deep sea dump

3 Refloat in absence of cuttings, dismantle inshore, dispose waste onshore 4 Refloat in presence of cuttings and deep sea dump 5 Refloat in presence of cuttings, dismantle inshore, dispose waste onshore

1 Leave untreated in-situ 2 Bury in pit in-situ 3 Bury by rock dumping in-situ

PILE OF DRILL 4 Cap with membrane in-situ

CUTTINGS 5 Controlled spreading in-situ 6 Retrieve, treat and dispose onshore 7 Retrieve and dispose onshore untreated 8 Retrieve, treat onshore, deep sea dump treated material 9 Retrieve, dump untreated in deep sea 10 Retrieve, re~inject down wells

1 Leave untreated in-situ • 2 Treat internally, leave in-situ 3 Plough and backfill in-situ

PIPELINE 1 4 Rock dtunp in-situ 5 Remove spans and dispose onshore, leave remainder in-situ 6 Remove spans and deposit at reef, leave remainder in-situ 7 Remove spans and deep sea dump, leave remainder in-situ 8 Totally remove and dispose onshore 9 Totally remove and deposit at reef 10 Totally remove and deep sea dump

Figure 3.11. Variants for removal and disposal alternatives for different structures and needs (UKOOA, 1995 - modified).

55

The fact is that once public opinion is engaged in demanding total decommissioning, the

matter becomes highly politicized and companies are forced to adopt economically unsound

solutions, as it happened in the Brent Spar case. This scenario seems to indicate that two main

aspects are fueling the total or partial decommissioning dilemma: the amount of money involved

in the decommissioning process, and a feeling of "public mistrust" towards the oil industry.

Indeed, the Brent Spar episode has brought the necessary attention to the matter and the public

felt that oil companies should not be trusted. As a result, even though it can be argued that

environmental benefits of "total removal" against "partial removal" are only marginal, and, in

some cases, leaving the structure in place would increase the ecosystem value, public opinion

tend to go in the opposite direction. According to ATHANASSOPOULOS et a!. (1999), the

main public objection in regard to the presence of non-producing installations in California

would be the perceived damage to the scenic ocean-views.

An innovative approach used by Phillips/66 Norway to manage upcoming

decommissioning operations has received the approval of Greenpeace. Recently, Phillips/66

Norway invited all interested stakeholders to present their opinion during the decision-making

process for the decommissioning of oil platforms from the North Sea Ekofisk I field (public

involvement plus transparency). As a result, Greenpeace welcomed Phillips/66 Norway's

proposal for the decommissioning of all fourteen steel oil platforms from Ekofisk I. According to

Greenpeace, since it will be by far the largest upcoming decommissioning project in the North

Sea, these operations should boost the development of the onshore decommissioning industry.

Over the next few years, fourteen steel platforms and one concrete offshore installation will be

decommissioned, dismantled, and taken onshore (PHILLIPS, 1999a, 1999d).

Greenpeace has still criticized Phillips for its intention to leave drilling muds below the

platforms on the seabed. According to the environmental organization, "this will be the next

major issue where the oil companies will have to face their industrial responsibility to clean up

their acts" (GREENPEACE, 1999).

The attenuation of impacts caused by decommissioning expenditure depends on planning

and proper project administration, allowing significant cost and liability reduction. To some

specific segments, decommissioning has become a great market opportunity. Offshore structures

and their components are being regarded as assets (scrap, resale or reuse) and economic impacts

are being reduced.

56

150

100

Meters

50

0 DeepWater Structure

LARGE

Figure 3.12. Comparative scale indicating the size of small and large structures compared to a 20-story building (Griffin, 2001- modified).

WASTE HIERARCHY FACE

REUSE FACE

Figure 3.13. Environmental character of the reutilization principle (TILLING, 2001 -modified).

57

In the GOM Region, scrap credit is approximately US$ 100/ton (O'CONNOR, 2000).

Independent contractors are also positioning themselves in the ex-post market including recycling

centers, re-adaptation facilities, used platform brokers, etc. (THORTON, 1997). In addition, in

the attempt to maximize investments by delaying ex -post costs as much as possible, maintenance

and modifications services are increasingly being required. Clearly, this is boosting the sector.

Regarding the reuse of offshore facilities, best practice in GOM suggests that 10% of

facilities being reused at the end of field life would be an ambitious goal. In the majority of

cases, there will be no alternative to scrapping, salvaging the high value components, and

recycling the remaining materials (SILK, 2001 ).

In most cases, the resale value of old offshore structures, equipment, and parts of it, will

not be sufficient to generate enough revenue to cover decommissioning costs. Due to

marketability and technical practicability, several companies are not motivated to pursue reuse

options, also called recommissioning. The industry is joining forces with authorities searching

for strategies to change this "culture", promoting the reutilization of components and

recommissioning of facilities.

On the other hand, TWACHTMAN (1997) points out that rising costs for fabrication of

new decks, jackets, and pilings, are stimulating the commercialization of decommissioned

platform components. Providing that not many modifications are required in the old platform,

the use of decommissioned platforms will avoid costly fabrication costs, and even anticipate first

oil. In fact, at least in GOM, the market for used platforms has increased. According to

THORTON (2001), each year in GOM, around 100-120 platforms are salvaged (supply), and

120-140 new platforms are installed (demand). Only 35% to 50% are suitable in age and

conditions for recommissioning, but no more than 20% of the decks and 10% of the jackets are in

fact reused. The first platform reutilization occurrence was recorded in 1967 when Humble Oil

moved and reused South Pass 36A (O'CONNOR, 1999).

Most modules contain equipment that are installation-specific and may not be readily

reusable in other installations (i.e. equipment from power generator modules, wellhead modules,

processing module, accommodation modules, and safety-related facilities). Adaptations of

equipments from redundant facilities may incur discouraging costs. New installation

requirements may expect features that cannot be accommodated by old installations or can imply

unacceptable expenditure (WATSON, 1998). PRASTHOFER (1998) indicates the difficulty in

58

ensuring the integrity of structures that may be 20 to 30 years old. Additionally, there is the issue

of meeting new decommissioning requirements.

WATSON (1998) indicates that parameters that might benefit the reuse market are: (!)

high-value; (2) long delivery period for new installations11; (3) good match between what is

offered and future needs; (4) an age of less than 10 years; and (5) an engineering mindset and

reuse culture. Equipment such as power generators, water injection devices, and other items not

affected by corrosion, have high potential reuse value; at least when a good match is found. Used

equipment should offer competitive prices, cost-effectiveness, and acceptable safety levels. In

addition, reused equipment may offer cost, schedule and image benefits. Those in the market are

challenged with an extremely conservative industry that requires proven technology, risk evasion,

and are extremely sensitive to oil spills. Table 3.1, as proposed by WATSON (I 998), indicates a

comparison between costs associated with getting a new installation and a refurbished one.

TilLING (200 1) proposes a nonexclusive criterion for evaluating the possibility of

reusing platforms and "who" would be best handling each criterion among stakeholders.

Appendix 2 suggests a similar approach in order to evaluate the possibility of recommissioning.

Each criterion has 50-50 chances to succeed. A perfect match is indeed very improbable. Figure

3.13 illustrates the environmental character of the reutilization principle related to the degree of

difficulty.

TABLE 3.1. COST COMPARISON: REFURBISHED vs. NEW

Refurbished New

Engineering & Management 200,000 240,000 Jacket & Piles 650,000 1,225,000

Deck 365,000 965,000

Installation 600,000 600,000

Miscellaneous 100,000 700,000

Total 1,915,000 3,730,000

WATSON (1998)- modified

If reuse is a real option, timing must also be adjusted (Figure 3.14). Other important

factors for a successful reutilization project include matching oftechnical requirements, sufficient

time to match market parties, detailed intelligence network, full technical and maintenance

records, a set of guidelines12, and an extremely knowledgeable project team (RIK, 2001; BECK,

11 The availability of marginal fields requires the reduction of the time between the decision to develop and the first oil flow. 12 Several large oil corporations have join together to develop guidelines for platform reutilization (BECK, 2001).

59

2001 ). In addition, liability conditions must be clearly defined. Table 3.2 illustrates a successful

case history.

TABLE 3.2. CASE HISTORY- EI300 A- GOM Drilling/Production

OD Piles

Installed

Removed

Deck Sold

Removal preparation cost

Removal cost

Site clearance

PM!Engineering

Gross Cost

Deck Sale

Net Cost Source: BECK (2001)

60.5 meters (water depth)

1.5 - 14.5 meters 1981 1996 1997

Costs in $MM 0.057

1.121

0.020

0.144

1.342

0.635

0.707

If leaving the platform fully in place is an option, maintenance and surveillance will be

required. In certain circumstances, a company may decide to leave an installation in place for a

period (stand by) or even give it an alternative use (meteorological, geologic, oceanographic and

seismologic offshore research facilities, lighthouses, monitoring stations, field laboratories,

commercial enterprises such as marine culture and tourism, etc.). In all circumstances, the

installation must be completely cleaned, monitored, and, eventually, decommissioned.

As mentioned above, reutilization alternatives may include non-petroleum considerations

(in situ or relocated). Two very interesting alternative uses given to offshore platforms are: (1)

the Sea Launch Co., a partnership between Boeing Commercial Space Co., Kvaerner Maritime

A.S. (a vessel builder from Norway), RSC Energia of Moscow, the Russian Government, and the

KB Yuzhnoye/PO Yuzhmash of Ukraine (SEA LAUNCH CO., 1999). The Sea Launch Co.

provides marine-based commercial satellite launches from a converted Norwegian oil-floating

platform in the equatorial Pacific Ocean (Figure 3.15); and (2) economic feasibility studies are

underway to test the viability of reusing offshore installations as platforms to generate eolic

electricity using Wind Energy Converters (OWEC) and other renewable energy systems in the

North Sea. The main motivation is to offer an alternative to near term decommissioning.

The comparison between several decommissioning options (toppling, partial removal and

total removal) is strongly influenced by the energy cost of replacing material that is lost in the

60

process. This is an externalized cost not borne by companies that if ignored may turn options

such as toppling more attractive in this respect (UKOOA, 1995).

The industry needs comprehensive region-specific studies on the socio-economic impacts

of available decommissioning options in order to internalize decommissioning costs more

accurately into its decision-making process. The internalization is complete when the fees equal

the marginal external damages (CARRARO, 1999). Additionally, the elaboration of complex

models that can embrace most relevant issues (environmental and societal) would be an

alternative approach for obtaining balanced results that could be more efficiently communicated

to stakeholders.

In order to identify the preferred decommissioning options, HUGHES and FISH (1999)

suggests a technique based on the methodology developed by KEPNER and TREGOE (1981),

often used to evaluate bid proposals. This methodology consists in assigning scores to each

option based on predetermined selection criteria for objectives in order to arrive at a ranking for

the options. When all legal requirements have been met and all legal options have been

identified, the oil company would consider the following objectives: Environmental, safety,

technical feasibility, cost, and public acceptability. The Kepner-Tregoe analysis method13 ts

outlined bellow in steps, as described by HUGHES and FISH (1999):

• Establishment of objectives, which each of the decommissioning options is to be

evaluated against.

• Classification of objectives into two categories: "mandatory" and "desirable".

• Attribution of weighting (ranking) to each "desirable" objective, indicating its relative

importance, assigning the highest weighting to the most important objective.

• Selection of all options that will be considered.

• Identification of all options that satisfy "mandatory" objectives. The remaining

options are discarded.

• For each "desirable" objective, a score to each decommissioning option should be

assigned. Judgments can be based on qualitative or quantitative considerations, but

are best arrived at as a team, rather than individual effort.

13 This approach described by KEPNER and TREGOE (1981) dates from the 1970s. This method is widely known and allows it to act as a shared language amongst its users.

61

• For each decommissioning option, calculate the weighted score for each "desirable"

objective. Then calculate the total weighted score for each option.

• The preferred decommissioning option(s) are the ones having the highest weighted

score.

• Analyze the sensitivity of the ranking to the weightings.

• For the decommissioning options having the highest scores, consider potential

problems including option not feasible at the time of decommissioning and problems

occurring during the actual decommissioning. Score the probability of failure for each

decommissioning option (high, medium or low). Use Table 3.3 to evaluate if the

possibilities of failure are acceptable.

• Decide on the preferred option.

• Table 3.4 shows, according to HUGHES and FISH (1999), a summarization of the

results of the application of Kepner-Tregoe analysis.

TABLE 3.3. RISK ASSESSMENT BASED ON PROBABILITY OF OCCURRENCE AND CONSEQUENCES

Probabili!Y of occurrence Conseguences High High High Moderate High Low

Moderate High Moderate Moderate Moderate Low

Low High Low Moderate Low Low

HUGHES and FISH (1999) modified.

TABLE 3.4. SELECTED DISPOSAL ROUTE

Jackets Topsides Subsea Structures

Highest Score Alternative Use Alternative Use

Remove and Reuse Pipelines Leave in Place Umbilicals & Flexible Pipelines Leave in Place HUGHES and FISH (1999) modified.

62

Is failure acce(!table No No Yes No Yes Yes Yes Yes Yes

Recommended Recycle Onshore Recycle Onshore Recycle Onshore

Leave in Place Leave in Place

Production Begins

Anticipate or Delay Recovery Operations("'}

====--=-=-~-------------=========~ I' }Exploration! ~0-eve'r~'Pmeilt" '-'£?;;&:v '' 'v V

(On Going Project)

t

: I <*I !Oil Price Variation I I I I I I I

+ (New Project)

Production 'ec~_fn'in_ ost Decommissioning

~-=----~-------~ Anticipate or Delay Decommissioning Operations("')

~:)

Figure 3.14. Reuse timing adjustment. When a match is achieved for the reuse of a platform, timing also has to be matched. Recovery and decommissioning must be adjusted. Oil price is, most ofthe times, the main variable.

Figure 3.15. Sea Launch Lift (courtesy of SEA LAUNCH CO.).

63

3.6. THE US RIGS-TO-REEF PROGRAM

Offshore facilities attract a variety of marine creatures to their reef-like structure (DITTY

et al., 1997) (Figure 3.16). Marine organisms are not the only wildlife attracted to offshore

facilities. Every spring and fall, several species of neotropical migrating birds use GOM

platforms as resting places during adverse weather conditions. Thousands of Monarch butterflies

also use GOM platforms as resting spots during their migration across the gulf (MMS, 2000b,

2000c).

Productive offshore oil and gas structures form one of the world's most extensive defacto

artificial reef systems (DAUTERNE, 2000a). Removal of redundant facilities is not only a

financial liability for the petroleum industry but can be a loss of productive marine habitat

(KASPRZAK, 2000).

The Louisiana Department of Wildlife and Fisheries, in the United States, manages one of

the most active artificial reefs program in the world. One of the reasons for this is that through

December 1999 over 1835 rigs were removed from the GOM. This program was designed to

take advantage of fishing habitat opportunities offered by these obsolete platforms (KASPRZAK,

2000). Other materials have been tested as substrate for artificial reefs including aircrafts, war

tanks, subway cars, etc.

In 1977, Mobil Oil requested permission of the US government to modifY and abandon in

situ the accidental wreckage of the drilling rig Topper Ill as an artificial reef at 143 Km from the

coast of Texas (REGGIO, 1989). After a number of success histories, US authorities established

programs allowing the use of abandoned offshore structures in the construction of artificial reefs.

Offshore structures are the ideal substrate form marine life because of their weight and durability.

US legislation enabled oil companies to donate offshore structures to entities such as the

Texas Parks and Wildlife Department (TPWD). Along with structure donation, companies are

required to pay a fee equivalent to half of the total decommissioning cost saved (removal and

cleanup), or negotiate an alternative "contribution" with the applicable authority (MMS, 1987,

1997a, 2000b, 2000c; DAUTERNE, 2000a, 2000b). These fees provide the means to the

implementation and maintenance of a controversial artificial reef program called Rigs to Reefs.

Sometimes contingencies may anticipate decommissioning, as it is the case of several

platforms destroyed by hurricanes in GOM. When such accidents occur, platforms are left in

64

situ. In 1992, Hurricane Andrew destroyed or damaged over 181 active platforms and caissons,

five of which subsequently entered the Louisiana Artificial Reef Program (KASPRZAK, 1998).

By the end of 1998, approximately

125 offShore structures (around 10% of ail

decommissioned structures) had been placed

on tbe seabed at disposal sites as permanent

artificial reefs. The states of Louisiana and

Texas have received over US$ 15 million

from projects they have sponsored

(REGGIO, 1998). Table 3.5 shows an

estimate of potential opportunities to reduce

decommissioning costs by implementing the

Rigs-to-ReelS program. In California, the

Rigs-to-Reefs Bill has been resubmitted to

the State Senate and Assembly in 200 I.

Since this bill has been withdrawn before,

the industry is teaming up with non-industry

Figure 3.16. Islands of Life. Marine organisms attach supporters (non-profit public benefit themselves onto the hard substrate of offshore structures initializing the food chain which leads to the creation of a organizations, sport fisherman, divers, unique ecosystem that ends when platforms are removed.

environmentalists and conservationists) in This areas work as a fish recharge area helping our

overfished oceans (Photo: MMS, 2000c). order to establish an active advocacy through

communications and presentations (STEINBACH, 2000). All the uncertainty involving potential

ecological benefits of California artificial reefs and residual liabilities that would be ultimately

transferred to government entities seems to be a unsurpassable roadblock in the negotiating

process (ATHANASSOPOULOS et al., 1999). Other issues concerning the ecology of

decommissioning options can be found in MCGINNIS (2001).

TABLE 3.5. RIGS-TO-REEF OPPORTUNITY TO REDUCE COSTS IN CALIFORNIA

Full Removal Cost Estimate Rigs-to-ReelS Cost Estimate Savings (Before Donations) Source: STEINBACH (2000)

65

(US$ million) 1,253 595 658

The MMS maintains a partnership with state agencies for the establishment of these

artificial reefs. Before being sent to a designated location, structnres are cleaned. Then, the

company donates the structnre to the State, transports, and places them in a designated area. The

State assumes all residual liabilities.

Artificial reefs not only improve certain ecosystems but also create new business

opportunities. The artificial reef program has:

• Established a market for sport fishing;

• Created recharge cells for the overfished GOM, improving conditions for the

commercial fishing industry;

• Provided research material for universities; and

• Generated valuable resources.

Technical requirements include:

• Maintenance of at least 25 meters of water colunm clearance; and

• Reef areas are designated in zones having depth between 60 and 90 meters, where the

ecosystem can be improved by the presence of structnres.

The artificial reef concept for offshore structnre disposal has not been accepted

unanimously. For instance, North Sea producing nations and the State of California are still

debating the issue. Authorities and the industry agree that there is very little to gain in

establishing artificial reefs in the North Sea environment (deep, cold and cloudy waters), and

artificial reefs programs would be just a convenient way of "dumping" offshore facilities.

0 'LEARY et al. (200 I) has comprehensively discussed the feasibility of artificial reefs in the

North Sea, and TAKAGI (1998) has conducted similar studies for Japan. Despite all ecological

and societal aspects, probably the most unsurpassable predicament lies on "residual liabilities".

Most governments are not willing to accept the uncertainties of artificial reef programs.

Existing artificial reef programs in Louisiana, Texas, and Italy are, undeniably, very

successful. However, success stories are associated to a combination of ideal environmental

conditions (where ecosystem services can be improved), available redundant offshore structnres,

and a favorable legal scenario.

66

3.7. ENVIRONMENTAL, HEALTH, SAFETY, AND SOCIETAL CONSIDERATIONS

Usually, before an installation is decommissioned, authorities require a detailed safety

analysis. Operations involved in the decommissioning process comprise several potentially

hazardous operations that offer safety concerns towards workers involved in the process (divers,

mechanics, welders, etc.). Even recycling has its own safety and pollution risks.

The ODCP14 Research and Technology Assessment Program Report shows that safety

risks are approximately 50% higher for the total-removal alternative compared to partial-removal

alternatives. Consequently, reducing offshore decommissioning activities is a determinant factor

in reducing risks (PRASTHOFER, 1998).

In analyzing the environmental impacts generated by tlte several decommissioning

options available today, some considerations should be made:

• Thus far, a great number of ships, railway wagons, war tanks, etc., have been sunk around

the world offering a much greater potential for environmental damage.

• Natural occurring heavy metals are present in mid-oceanic ridges and thermal vents.

• Organic matters, heavy metals, and halogen organic compounds are present in large

amounts in effluent discharges by rivers, ducts and occur in natural seepage under the

seabed.

Those occurrences, botlt natural and previously man induced, should be used to provide

scientific data for further decommissioning studies, but not as an excuse for irresponsible

disposal of offshore installations.

The geographical extent of impacts from the deep-sea disposal will depend on a number of

factors such as topography, sediment characteristics, dispersion and transport patterns, etc.

Considering that structures are prepared in such way that only a limited amount of harmful

substances remains, no severe enviromnental damage is anticipated during decommissioning

operations. Besides, enviromnental impact resulted from several decommissioning options seems

to be not significant (PROGNOS, 1997).

14 The Offshore Decommissioning and Communications Project (ODCP) was disbanded in September 1998. The ODCP operated for two years under tbe sponsorship of tbe OGP (then tbe E&P Forum), UKOOA (UK Offshore Operators Association), and OLF (tbe Norwegian Oil Industry Association). The OGP Decommissioning Committee was established in October 1998 to take over tbe work oftbe ODCP.

67

A recent study conducted by LINDEBOOM (2000) of tbe Dutch Institute for Marine

Research (NIOZ), on Texel, compares environmental effects of trawler fishing, sand extraction,

and oil and gas drilling in the Dutch part of tbe Continental Shelf, in the North Sea. The study

concludes that fishing has tbe most disturbing effects on biodiversity. Plowing the top layer of

the soil with heavy nets is very harmful to crabs, shrimps and starfish, favoring only certain

worms on which flatfish feed. Offshore platforms, according to this study, even have a

beneficiary effect on the ecosystem. Part of it is because fishing within 500 meters of a platform

is prohibited. This interdiction is questioned by NGOs connected to the fishery industry.

Commercial fishing is also not allowed on the proximities of artificial reefs. This issue tends to

get very emotional since it provides an "easy way out" for oil companies, and, at same time, a

way to restrain the abuses of commercial fishing in overfished areas. FERREIRA and

BOUMANS (200 1) (Figure D.5) presents a carbon model where ecological impacts of offshore

platform removal are accessed. Several other issues concerning the fishery industry are raised by

OSMUNDSEN and TVETERAS (2000).

There are topics tbat are not comprehensively addressed by international legal provisions.

Sea-floor sediment pollution by discarded drilling muds such as barite (BaSo4) used for specific

gravity control may contain significant quantities of heavy metals sulphides (e.g. PbS, ZnS,

FeS2), among other compounds and additives (UAFSE, 1999; PEREZ, 1997). Health risks may

also be involved during onshore dismantling and waste disposing activities. During tbe 1990's

the presence of Natural-Occurring Radioactive Material (NORMs)15 in waste, fluids and gases

brought to tbe surface from producing subsurface oil and gas formations, has become a great

concern for the oil industry (MCFADDIN, 1996; RYGH and BONIFAY, 2000).

Decommissioning plarming must consider specific handling of NORM-bearing waste, which are

usually deposited onto the seabed, and NORM-contaminated material, such as drilling

equipment, well tubing, pumps, etc. These procedures have not been adopted in the majority of

producing nations.

Dealing with the recovery and disposal of drill cuttings may be very complex. As in other

issues, there are several technological, safeties, and economic challenges involved in tbese

activities. Leaving drilling muds in situ would probably be the best available alternative. It

15 Radioactive materials have spontaneous decays over time emitting ionizing radiation. Such radiation can cause biological dan!age to individuals who are exposed to it, increasing the risk of cancer and birth defects (MCFADDIN, 1996).

68

should be noted though, that environmental impact might also occur as a result of long-term

presence of endpoints16 on the seabed.

This scenario does not seem any better when dealing with pipeline decommissioning.

Potential environmental impacts from several disposal options may include emissions of heavy

metals, emissions of oil/tars and softeners, emissions to air, water and land, impacts on habitats,

and littering of the seabed (MUSAEUS, 2000). In this case, the best environmental solution,

safest, and most cost effective option, may be leaving pipelines in place, but this issue will

probably attract scores of emotional disputes.

HUGHES and FISH (1999) indicate that all disposal options involve secondary C02

emissions and other gases to the atmosphere. The author also points out that if installations were

disposed of offshore (i.e. deep-sea dump), there would be a cost in replacing lost material.

Marginal energy savings will result if total removal options are adopted. However, if the

necessary precautions were taken, environmental impact would be at acceptable levels, regardless

of the disposal option.

An Environmental Impact Assessment Report (EIA) can preclude many problems by

suggesting mitigating measures to reduce negative impacts and enhance positive ones (NESSE,

2000). An EIA can also provide basis for balanced decisions, better awareness of risks and

knowledge oflegal requirements.

Lately, regulators have been motivated to consider social impacts produced by offshore

activities, and, principally, impacts emerged after the end of activities in nearby communities.

For instance, a small costal village begins to change rapidly after the discovery of offshore oil in

the region; establishment of field offices and support facilities, helicopter transport companies,

hotels, supermarkets, etc. The great challenge is to avoid that at the end of activities, when the

resources are depleted, communities that have become dependent on the benefits brought by

nearby operations are disrupted. Oil companies are motivated to work with these communities

establishing infrastructure and stimulating alternative productive activities that may substitute, or

at least attenuate, the void expected after operations are concluded. Undoubtedly, social issues

are significantly more complex tl!an environmental issues.

16 Endpoints: remains, such as structures, concrete bases, drill cuttings, etc. an example of endpoint effects is the deterioration of steel left on the seabed.

69

3.8. TECHNOLOGIC AND TECHNICAL CONSIDERATIONS

Frequent periods of high oil and gas prices have been encouraging governments to offer

fiscal incentives and royalty relief in order to turn small and marginal fields viable. Such projects

attract the attention of independent and small operators. With the aim of optimizing profit, new

approaches are being directed to technology and concepts that allow more attractiveness in the

development of some shallow water fields. Economic incentives and the emergence of new

concepts by minimal platform designers are yielding a renaissance in the technology and use of

minimal facilities, as pointed out by ALBAUGH eta!. (2001).

Old platform designs can add significant challenge to decommissioning operations.

According to the MMS (1997b), current technology available for platform removal includes bulk

explosives, shaped explosive charges, mechanical cutters, and underwater arc cutters. For the

industry, explosives are the most commonly used, safest, most cost-efficient, and most reliable

method for severing piles and conductors of platforms. Removal methods for GOM Region from

1986 to 1997 were explosives (67%), mechanical (28%), abrasive (4%), and other (1 %)

(O'CONNOR, 2000). However, because of the threat to marine animals, including turtles and

dolphins, it remains a very sensitive topic among environmentalists and the general public.

Probably, for this reason, related research sponsored by the MMS has intensified: (I)

Overpressures developed by shaped explosive charges used to remove wellheads; (2)

Environmental effects of wellhead removal by explosives; (3) Blast effects upon the environment

from the removal of platform legs by explosives; (4) Development, testing and evaluation of an

explosive shock wave focusing tool with minimum explosive weight; and (5) Effectiveness of 50

pound bulk charges in cutting platform members (MARTIN, 2000).

The industry has accumulated considerable decommissioning experience along the years,

however removing large and heavy installations (steel and concrete) in deep waters and rough

seas can still be particularly complex. Some of the challenges found in these operations involve

underwater cutting of thick concrete and steel, lifting sections in excess of 4000 tons, diving in

deep, cold, harsh waters, loading large and heavy structures onto barges in open sea, scarce

equipment, and removing concrete structures where reflotation could be unpredictable.

The most common risks involved in decommissioning operations in deep waters are

potential equipment damage or Joss. Some other potential contingencies are: sinking of

installations; dropped loads during marine operations; dropped loads during outcome/end-use

70

phase of the work; loss of a towline during severe adverse weather conditions; and diving (DNV,

1995). Such risks are considered tolerable since the likelihood of that scenario and their

consequences are considered low.

Aiming at reducing decommissioning costs and minimizing capital and operational

expenditures on marginal fields, the industry tends to avoid producing large structures. Since

many structures were constructed with a fatigue life of 100 years, capable of withstanding winds

in excess of 160 kilometers per hour and waves as high as 30 meters, companies are looking at

ways of reusing offshore installations.

New breeds of offshore structures are designed with economic and environmental

advantages, weighting less, being more easily lifted and transported, and offering the opportunity

for reuse on new development projects. The new trend goes in the direction of the "Minimum

Facility Concept", involving usually unmamJed platforms, ranging from self-installing gravity

platforms and twisted-base jacket structures to 3-legged tension leg platforms, offering

environmental features and partial or total reusability (ALBAUGH, et al., 2001; O'CONNOR

and ROBINSON, 2001). Other concepts are also being pursued, such as the platformless17

development in deep waters (Figure 3.17). 1n the near future, technology leaps may offer

profound impact on developments. Common use of mechanisms such as seabed separation and

extended wellstream transfer to onshore plants may become a standard approach to development

projects. Platformless development may become tomorrow's main option, since it may provide

ways of reducing both cost and implementation, and, additionally, reducing decommissioning

costs.

Other examples are the mini-jacket platforms used in the coast of West Africa and the

Maureen platform, used at the North Sea. The Maureen platform is a large gravity base platform

that has been used for oil production, processing, and storage in the North Sea since 1983. The

platform is 235 meters tall and weights 110,000 tons. Three large ballast tanks form the base of

the platform, which is held on the seabed by gravity (virtue of its weight). The Maureen can be

completely refloated and reused in a different location (Figure 3.18).

The number of innovative offshore technology becoming available since the Brent Spar

episode has increased significantly. Most available technologies have only been tested in the

GOM Region. Some of these technologies are mentioned by TW ACHTMAN (1997), and

17 Platformless deepwater production systems.

71

HUGHES and FISH (1999): the Versatruss system, the master Marine Catamaran System, the

RAMBIZ catamaran dual crane vessel used for bridge installations, the Norwegian Offshore

Shuttle System, and the Controlled Variable Buoyancy System (CVBS) for refloating

substructures. Most of these technologies are not yet available but in developing stages. Once

again, the motivational fuel is cost reduction.

3.9. ECONOMIC CONSIDERATIONS

The two main decisions affecting ex -post costs are timing and decommissioning options.

Decommissioning timing is based on production flows, economic criteria, and establishment of

financial models. Decommissioning options depends on regulations, environmental, safety and

economic criteria, and, frequently, public reaction.

Regarding timing options for decommissioning operations, there are basically three

possible scenarios: (1) remove installations progressively as each becomes redundant; (2) remove

in contractual groups; and (3) remove all installations at the end of field life. According to

HUGHES and FISH (1999), removing all installations at the end of field life often allows the

lowest decommissioning cost18. This happens because of high costs involved in relocating the

limited number of heavy derrick barges and rigs to offshore production areas. If a company can

coordinate more than three decommissioning operations in the same region, limited and valuable

ex-post capital will be saved. For this same reason, cooperation among different operators may

allow significant savings, as demonstrated on Table 3.6.

TABLE 3.6. JOINT INDUSTRY APPROACH TO REDUCE COSTS IN CALIFORNIA Components Wells Pipelines Platforms Onshore Disposal

Source: STEINBACH (2000) Total

Savings (US$ million) II 16 92 31

150

18 Some regimes enforce a !-year period for decommissioning of installations once recovery activities cease. In such cases, production can be extended marginally in order to adequate end-of-production with neighboring platform schedules.

72

Figure 3.17. Platformless Field Development. Subsea to beach technological breakthrough. Field development costs are reduced in up to 30%. Source: Norske Shell (LEONARD. 2002 -modified).

Figure 3.18. Schematics of the Phillips Maureen (PHILLIPS, 1999c).

73

As indicated by HUGHES and FISH (1999), the most efficient way to determine optimum

timing for ex-post activities is to examine the field production tail-down and cash flow forecast.

This careful modeling process should produce charts indicating periods of uneconomical

operations when OPEX exceeds revenues. This assessment would involve several studies

including forecast analysis of future oil prices and corporate taxes. Sensitivity analyses would

show different tail-downs for each scenario and decision-makers would decide on the optimum

timing for ceasing production.

Because of inherent uncertainties, estimating future decommissioning costs can be a very

complex task. Currently, a wide range of decommissioning cost estimates for large heavy

platforms were made available in the literature19• Inconsistent numbers can be blamed on the

limited experience available. Regarding cost, the decommissioning process seems to be

analogous to the development process: costs for decommissioning large installations in sensitive

areas usually have the same order of magnitude as costs for developing the project. Platform

removal and disposal costs are not the only disturbing aspect of offshore decommissioning

projects. As indicated by GARLAND (2000b ), in some areas of the world, well plugging and

abandonment operations may represent up to 50% of the total decommissioning cost. These

operations involve great technological challenges and substantial uncertainties, such as

complying with well plugging and abandonment requirements at great depths (i.e. over 2,000

meters). Cost estimates will greatly depend on available technologies. This factor can certainly

be used as a catalyst for technological research.

Other signs for higher decommissioning costs are noticeable. For instance,

TW ACHMAN (1997) calls attention to: (1) the limited number of derrick barges and rigs; (2)

expanded exploration; (3) tough production requirements; (4) growing number of installations;

(5) larger number of decommissioning projects; and (6) greater number of complex projects

involving larger platforms in progressively more difficult places. Additional reasons includes:

( 1) the advent of new production zones in developing countries (i.e. Brazil, Asian Pacific

countries and West African countries), which tend to increase the demand for the already limited

number of equipment and vessels; (2) stringent regulations; and (3) rigorous_clean-up standards.

19 There are several studies providing cost evaluation for different decommissioning options; however, due to the dynamic character of technological development, such assessments must be frequently revised.

74

also provide substantial savings (DELLA, 1997). Unplanned delays may result in additional

expenditure such as cost with maintenance, insurance, bond premiums, and fees that still have to

be paid until the installation is removed. Although it may increase operation costs, maintenances

will avoid contingency expenditures. Contractors specializing in different sorts of installation

work (adaptations, maintenance, etc.), have an expanding market ahead.

3.10. DECOMMISSIONING COSTS

Table 3.7 indicates some recent estimate and actual decommissioning costs in different

regions. According to HUGHES and FISH (1999), when a new field development is in the

planning phase, decommissioning costs may look insignificant if examined by discounted cash

flow methods.

Indeed, towards the end of recovery, decommissioning expenditure becomes a

considerable burden to projects. Welcoming signs of culture change are evident, but

unfortunately, decommissioning expenditure is still viewed by some segments of the oil industry

as a lost investment where "funds are allocated and no revenues are generated".

According to COLEMAN (1998), between now and 2025, it should be expected that over

6,500 installations would be decommissioned at an estimated cost of US$ 20-40 billion. Until

recently, over 50% of the word industry expenditure with decommissioning was expected to

come from only three countries where almost 70% of all offshore installations were concentrated:

the United States, the United Kingdom, and Norway. Depending on regulatory developments in

some producing developing countries, this scenario may change. In some developing countries,

offshore exploration and filed development are increasing significantly (i.e. South America, West

Africa and Asian Pacific nations).

The North Sea oil field is viewed as a mature province. The estimated cost for the total

removal of all North Sea installations ranges from US$ 12 billion to 15 billion (GRIFFIN, 1998b;

PROGNOS, 1997). According UKOOA's estimates (1995), the total decommissioning cost for

offshore installations located at the UK section of the North Sea is approximately US$ 8.02

billion. Over the next ten years, some 50 UK installations are expected to be decommissioned at

an estimated cost of US$ 2.4 billion.

76

TABLE 3. 7. DECOMMISSIONING COSTS BY REGION, CATEGORY AND INSTALLATION TYPE

Region Estimated Costs O(!tion Reference Australia 1.0 Total SHINNERS, 2000

NS (UK+ Norway) 12.0-15.0 Total GRIFFIN, 1998b; PROGNOS, 1997

NSUK 8.0 Total UKOOA, 1995 CA 1.3' Total STEINBACH, 2000 GOM 5.01 Total GRIFFIN, 1998b Southeast Asia 1.5-2.0 Total GRIFFIN, 1998b Total World 20-40 Total COLEMAN, 1998

North Sea Numbers Estimated Costs OJ:!tion Reference Total Decomm. Cost 12.7 Total PROGNOS, 1997 Total Decomm. Cost 7.7-11.7 Partial PROGNOS, 1997 Annual Cost 0.9-1.4 Total PROGNOS, 1997 Annual Cost 0.3-0.5 Partial PROGNOS, 1997 Gov. Expenditure 4.9 Total PROGNOS, 1997 Gov. Expenditure 2.7-4.6 Partial PROGNOS, 1997 Revenue from decomm. 6.0 Total PROGNOS, 1997 Revenue from decomm. 4.9-5.4 Partial PROGNOS, 1997 Possible Recycling Earnings 0.5 Total PROGNOS, 1997 Possible Reclclin!; Earnin!;S 0.4-0.5 Partial PROGNOS, 1997

Site I Installation Type De(!th (m) Final Cost OJ:!tion Reference NS Brent Spar - shell Buoy na +1- 77.4 Total DNV, 1995 NS Mime- Norsk na na 4.62 Total NPD, 1998 NS Noroost Frigg- Elf na na 9.03 Total NPD, 1998 NS Odin- Esso (1995) na na 11.24 Total NPD, 1998 NS 0st Frigg- Elf (1993) na na 12.64 Total NPD, 1998 NS Ekofisk5 I (1999) na na 1.0 Total PHILLIPS, 1999a, 2000 NS Frigg (2000/01) na na na Total NESSE (2000) CA Exxon Belmont Island na 13.7 20.0 Total STEINBACH, 2000

CA Mobil Seacliff Pier na 9 15.0 Total STEINBACH, 2000; BROOKS et al., 2000

CA Chevron, Arco, Phillips, Texaco, na 20-83.5 72.0 Total STEINBACH, 2000 Unocal, Aera. Abn Rig Sharing SW ARS CA Chevron Platforms na 29-41.7 42.0 Total STEINBACH, 2000 GOM West Delta 76 A 4-pile 55 0.4 RRR O'CONNOR, 1999 GOM Eugene Island 300 A 4-pile 60 0.7 Reuse O'CONNOR, 1999 GOM West Cameron 563 A 8-pile 58 1.4 RRR O'CONNOR, 1999 GOM Jacket 0-6 0.05-0.5 na KASP~AK, 1998 GOM Jacket 6.1-30.5 0.5-1.5 na KASP~AK, 1998 GOM Jacket 30.6-61.0 1.0-2.5 na KASP~AK, 1998 GOM Jacket 61.1-122.0 5.0-15.0 na KASP~AK, 1998 GOM Jacket 122.1-610.0 15.0-100.0 na KASP~1998

GOM Jacket < 15 +1- 3.2 Total MMS, 1999b GOM Jacket 15-61 +1- 3.9 Total MMS, l999b GOM Jacket 61-122 +1- 9.8 Total MMS, 1999b GOM Jacket > 122 Up to 94.0 Total MMS, 1999b OC ( 4 Chevron platforms) na 30.5-42.5 +/- 56.0 Total MMS, 1999b Indonesia na 38.1 7.2 Total DJALAL, 1998 Indonesia (Java Sea) na na 1.0-4.0 N/A IDGOG, 1998 1The US Rigs-to-Reef Program allows lower decommissioning costs; 2Estimated disposal cost; 3Disposal cost; 4Accrued disposal cost; srncludes decommissioning operations in 14 installations (different installation types and decommissioning procedures); NS =North Sea; GOM = Gulf of Mexico; OC = Offshore California; na = not available; RRR = Reuse and Rigs-to-Reef; 6 Assumes platfonns are removed in ![OUps of4 to 5. All values in$ billion.

77

Noteworthy is the fact that the number of platforms in the North Sea province comprises

only about 7% of the total world platform population; but, as shown, it accounts for

approximately 35% of the total worldwide decommissioning expenditure20• The main reasons for

this discrepancy are the weight and structural complexity of the installations and the severe

weather conditions common to that region (PRASTHOFER, 1998). In addition, Norway

possesses a network of 7,500 kilometers of export pipelines (1/3 buried), and 2,000 kilometers of

interfiled pipelines (80% buried) (MUSAEUS, 2000). Up until 1997, over 1,500 platforms were

removed in the Gulf of Mexico and approximately 27 in the North Sea. Table 3.8 shows the

approximate number of installations in the North Atlantic Region, which includes the North Sea

Province, Table 3.9 indicates the estimated number of installations in the Mediterranean Sea

Region, and Table 3.10 indicates the estimated number of offshore installations in West African

Countries.

TABLE 3.8. NORTH ATLANTIC PLATFORMS Settings UK NORWAY NETHERLANDS OTHERS

Less than 10,000 210 72 106 12 Tons Jacket (Steel)

Greater than 10,000 Tons 27 6 0 0 Jackets (Steel)

Concrete 8 14 2 0 Installations

Source: TILLING. (2001).

TABLE 3.9. PLATFORMS IN THE MEDITERRANEA.c"! SEA REGION Countries Platforms %

Croatia 4 2

Egypt 18 9

Greece 4 2

Libya 2 1

Italy 142 71

Spain 6 3

Tunisia 24 12

Source: ONARGHI (2000).

20 The Norwegian State carries the majority of disposal costs.

78

TABLE 3.10. WEST AFRICA OFFSHORE INSTALLATIONS

Country Shallow Deep Floating Total waters waters installations

Nigeria 134 7 134

Cameroon 54 54

Gabon 71 3 71

Congo 67 3 2 70

Angola 220 2 220

Total*: 549

*Numbers do not include floating facilities. Source: GARLAND (2000a).

There are approximately 53 of!Shore production facilities in Australia (18 SPJ platforms,

16 Monotowers, 9 Subsea completions, 4 FPSO's, 3 CGS's, 3 minitowers, and associated

pipeline network). Significant decommissioning activity is not anticipated before 2010, with

most existing facilities removed by 2030. Current estimations indicate decommissioning costs in

the order of US$ 1 billion (SHINNERS, 2000). Decommissioning of all platfurms in Southeast

Asia is estimated to cost between US$ 1.5 and US$ 2.0 billion (GRlFFIN, 2000b).

Figure 3.19 illustrates the dynamics of installation and removal costs in GOM. Cost

estimates for decommissioning of Gulf structures are lower than one would expect. This is due

to the success of the US Rigs-to-Reef Program, which brings down ex-post expenditure.

1600 1480

1400

"" (/) 1200 2-c: 1000 0

~ 800 0 553 () 600 <f) <f)

400 e CJ

200

0

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Year

Figure 3.19. GOM Historical of Decommissioning Costs: Gross Cost Per Ton, Excluding Well P&A. Note: Gross Cost Per Ton considers all decommissioning costs except well P&A divided by total fucility weight, including jackets, piles, and topsides, based on 54 actual platform removals (TWACHTMAN SNYDER & BYRD, INC., 1999).

79

In the United States outer continental shelf, platform decormnissioning rate is increasing

and, in some instances, going beyond the installation rate. As remarkable as it seems,

approximately 620 wells are plugged and abandoned every year in GOM (PERRY ill et a!.,

1998). The number of platform decommissioned yearly in this same region is between 120 and

150 (WATSON, 1998). The MMS forecasts that 100 to 200 of structures will be

decormnissioned each year (BUFFINGTON, 1996). The estimated cost for completely

decommissioning all Gulf structures is US$ 5 billion (GRIFFIN, 1998c ).

Currently there are 105 offshore installations in Brazil (Table 3.11) (ANP, 2003). In

1998, around 50% of all Brazilian offshore platforms in the OCS were installed in depths greater

then 400 meters (ANP, 2002a). Since not many fixed platforms of this size have been removed

around the world, expertise is limited and cost estimates vary greatly. Removing floating

installations in the Brazilian OCS is significantly less costly than removing fixed ones. However,

the cost of plugging and abandoning wells in Brazilian deep and ultra-deep waters (over 1,000 m)

tends to pose additional complexities and costs. Complexities are also expected in site-clearance

activities.

TABLE 3.11. BRAZILIAl" OFFSHORE PRODUCTION INSTALLATIONS Type oflnstallation Floating Production Systems (FPS) Floating, Production, Storage and Offloading (FPSO) Fixed Production Systems Fixed Production Systems (concrete) Semi-Submersible

Source: ANP (2003) Total

March/2003 2 8

77 3 15

105

Brazil has only initiated its open market policy towards oil and gas exploration.

Therefore, no estimates for future decommissioning expenditure were found in the literature.

First decormnissioning activities are expected to take place in 2004 (RODRIGUEZ, 2000). Some

of the issues being currently considered in the Brazilian scenario are: regulatory framework for

decormnissioning, removal options, reutilization of structures and equipment, and establishment

of an artificial reef program. No one seems to know for certain how many platforms have been

removed (or toppled in situ) in Brazil, if any (A."IW, 2000). Most new offshore projects in Brazil

are in ultra-deepwater sections of the OCS and involve floating installations. Currently (2003 ),

80

Brazil has 706 offshore producing wells (ANP, 2003). The estimated cost for plugging and

abandoning deep-sea wells could not be found in the current literature.

TABLE 3.12. ASSESSMENT OF PROPOSED OPTIONS FOR BRENT SPAR AMEC Civel Engineering:

• Preparation: This proposal covers only the end use phase. A different contractor must assume the preceding phases. • Destination: Barge transportation of rings sections from dismantling site to the North Norfolk Coast. • Process: Artificial Reef construction (placing ring sections, sand filling and rock dumping). • End use: Coastal Protection

Estimate: US $52,9 million Brown & Root Energy Services fBRESJ

• Preparation: Repair damage tanks and pressure reduction (divers). Removal ofhelideck and turntable. • Operations: Reverse upending (horizontal) in Erfjord by deballasting with winchline assistance. • Destination: Towing to Nigg, Cromarty Firth. • Process: Mechanical dismantling in dry-dock. • End use: Scrap and recycle.

Estimate: US $77 4 million. K vaerner Seawav Spar Alliance fKSSA)

• Preparation: Repair of damaged tanks and installation of hoses. • Destination: Tow vertically to Haneytangen yard. • Operations: Vertical out of water by de ballasting only. • Process: Cut into ring sections and lift by crane vessel. • End use: Training Center, Fish Farm or scrape and recycle. • Alternative: Reverse upending to horizontal, with dismantling in dry-dock.

Estimate: US $18 4 million and US $28 4 million McAlpine Doris Able CMCDAI

• Preparation: Remove helideck and turntable. Pressurize with inert gas via vent lines. • Operations: Reversed upending to horizontal in Erfjord by deballasting only. • Destination: Repair tanks. Tow to TERRC. Teeside .. • Process: Mechanical dismantling in dry-dock. • End use: Quay extension in dry-dock.

Estimate: US $31,6 million. Thvssen Aker Maritime CTHAMJ

• Preparation: Pressurizing via vent lines for ballasting to 90m draft in Erfjord. • Destination: Tow vertically to Hinna, Stavanger. • Operations: Vertical out of water by deballasting and jacking with tension bars to a cradle under the installation. • Process: Cut into ring sections and lift onshore. • End use: Scrap and recycle.

Estimate: US $34,4 million.

Wood GMC CWOGMI • Preparation: All work in Erfjord. Assembly of catamaran with cross barge. • Operations: Deballasting and jacking with strand jacks to a cradle under the installation. • Process: Cut into ring sections and skid to a barge. • Destination: Transport of sections by barge to Melgarvik, Stavanger. • End use: Quay extension using the ring sections. Scrap topside.

Estimate: US $34 7 million. Deep Sea Disposal CDSDI • Preparation: Removal of all accessible hydrocarbons. Installation of explosive charges. • Destination: Tow vertically to deep-disposal site. • Operations: Rupture Spar ballast tanks with explosives to get it to sink as one unit in a controlJed manner. • Process: Cut into ring sections and skid to a barge. • End use: None.

Estimate: US $7 6 million. Source: DNV (1995)- Modified

81

Partial removals cover a great range of different alternatives and combinations, and, if it

were a viable option in the North Sea Province, it would represent cumulative savings ranging

between US$ 1 billion and US$ 5 billion up until 2020. (PROGNOS, 1997). Costs savings

would range between 8% and 39%, depending on the variant (PROGNOS, 1997). During the

Brent Spar episode, several decommissioning options were evaluated by Shell. Table 3.12

shows an assessment of proposed options and respective costs for the disposal of the Brent Spar

Buoy.

Legal requirements and decisions from authorities will also play a decisive role in

determining decommissioning costs. For instance, if the length of a pipeline were required to be

removed rather than left in place, costs would increase substantially.

3.11. COST DRIVERS IN DECOMMISSIONING OPERATIONS

The method used to access decommissioning costs was the compilation of detailed

information obtained from the available literature. Necessary information to develop a

comprehensive list of decommissioning related activities for the Brazilian scenario was not

available. The main reason is that information relative to decommissioning costs for specific

projects are considered proprietary by the industry.

One of the objectives of this chapter was to provide general guidelines for regulators so

estimates for a range future decommissioning projects in the Brazilian OCS could be performed.

This study does not cover compliance with specific AN"'P requirements. In addition, costs for

specific projects will depend on several parameters, including planning and company's

capability, which allow cost internalization.

Firstly, several steps of the decommissioning process were identified in the literature and

related costs are briefly described bellow. Figures used are derived from assessments from

projects in offshore California, GOM, the North Sea, and according to MMS (1999b) estimates:

1. Engineering and Planning - costs will depend greatly of the size of the project, type of

structures and on the degree to which expenditures may be internalized. Basically, it will

depend on the availability of in-house expertise.

2. Permitting and Regulatory Compliance - it includes costs involved in obtaining the

necessary permits to carry out decommissioning operations, including fees to comply with

82

ex -post environmental requirements. This will greatly vary according to the regulatory

regtme. Estimating such costs for Brazilian projects is considerably complex. The

requirements are not yet clear and uncertainties are high.

3. Platform Preparation - costs are impacted mostly by size and complexity of installations.

Removal procedures, transportation and disposal, and degree of required structural

reinforcement, may offer a variety of price ranges. Internalization of expenditure is also an

important parameter. Cutting methods may significantly impact final costs.

4. Well Plugging and Abandonment- Costs for this phase will depend greatly from applicable

regulatory requirements, number of wells, and mainly on the difficulty and eventual

complications encountered. Well depth is a less significant factor compared to plugging

difficulty. Plugging and abandonment involve one of the most costly activities within the

decommissioning process.

5. Conductor Removal - costs for the removal of conductors will also depend on regulatory

requirements. The primary cost determining factor is water depth. Cutting methods may also

significantly affect fmal costs. If platforms have derricks and cranes capable of performing

the removal of conductor casing, the company may not need to contract a derrick barge,

significantly reducing costs.

6. Mobilization and Demobilization - It involves costs incurred to bring a HL V to the project

site and return the vessel to its point of origin. When there are no vessels with the capability

to remove platforms within the productive area, the vessel has to be brought from other areas

(usually from the GOM or North Sea). Total mobilization and demobilization time may vary

greatly according to distances between locations (i.e. 100 to 200 days.). Daily rates for HL V

rages from US$ 25,000 to US$ 310,000 per day, depending of the lift capability of the HL V.

It is important to notice that since there is a great demand for HL V's in the GOM for deep

water development, firms owning HLV's would not commit them to distant areas unless there

were at least five platforms scheduled to be removed.

83

7. Platform and Structural Removal - Removal costs will also depend greatly on the

regulatory requirements. The main variables in estimating removal costs include: size and

weight of the structures, the number of modules, the number of lifts, etc. Estimates for

removal in depths greater than 366 meters are very speculative and require technological

development. MMS estimations assume that it would take 8 hours to remove each platform

skirt pile, 8 to 24 hours for the removal of the main piles (depending on the water depth), 2

days per module, 2 to 5 days for sectional cuts and moves of the jacks. Contingency costs

should be expected (delays, weather conditions, etc.).

8. Pipeline and Power Cable Decommissioning - Cost estimates for the decommissioning of

pipeline and power cable decommissioning will depend on regulatory requirements which

will determine decommissioning procedures and disposal options. The main variables

affecting price include: length, size, pipe coatings, etc. Table 3.13 shows cost estimates for

different pipeline decommissioning options in Norway.

TABLE 3.13. COST ESTIMATES FOR DISPOSAL OF PIPELINES IN NORWAY

Total Burial Rock Dumping Removal Source: MASAEUS (2000)

(US$ million) 200-500

2,500 4,400

9. Transportation and Disposal - Transportation and disposal of material (process steel,

marine growth, cement, mud, etc.) may be very costly. Costs will depend on several factors

such as distance between operation and disposal sites, etc. The MMS assumes costs of US$

350 per ton of steel, US$ 300,000 per small platform for marine growth, cement and mud,

and US$ 700,000 per ultra-large platforms.

10. Site Clearance and Verification- Costs associated with site clearance and verification will

depend on regulatory requirements. The main variables involved are water depth; size of area

to be cleared and verified; quantity, size and type of debris; and the weather conditions.

Contingency costs should also be expected.

84

Due to the great range and combination of alternatives, estimating decommissioning costs

should consider each case separately, on a case-by-case basis. Table 3.14 shows MMS

estimations for most activities involved within the decommissioning process in offshore

California. This table provides estimations for different platform sizes. Table 3.15 summarizes

high and low decommissioning cost estimates for Table 3.14 and indicates the comparative

breaking-down of decommissioning costs as indicated by HUGHES and FISH (1999).

According to HUGHES and FISH (1999), the main "critical success factors" for any

decommissioning plan are (Figure 3.20):

• Maximize reservoir performance while minimizing decommissioning costs;

• Evaluate alternative field management strategies (this review would normally

include new prospects);

• Comply with relevant government legislation and guidelines;

• Develop contracting strategy to optimize overall field revenue and profitability;

• Develop a plan to ensure that decommissioning activities are correctly phased with

offshore removal operations so as to minimize unnecessary loss of production;

• Establish safe and economical removal methods for the platforms that are not solely

dependent on the use of any single methodology;

• Adopt safe engineering procedures;

• Minimize environmental impact;

• Recommend reuse of facilities where shown to be technically and economically

viable; and

• Promote acceptable disposal methods where reuse or recycling is not the preferred

option.

3.12. SUGGESTION FOR DECOMMISSIONING COST ASSESSMENT

Cost assessment of decommissioning operations still involves considerable uncertainties.

A variety of issues require further investigation and data collection. A comprehensive

assessment project is recommended for the development of a complex decision model that would

assist in the identification and quantification of potential impacts of management decisions

involved in the decommissioning process. Such model should consider the possibility of canying

out decommissioning activities at the end of project, or concomitantly with production. Table

85

3.16 illustrates a hypothetical project schedule sheet where decommissioning activities are

carried out parallel to recovery activities. It should also aid in the identification of an optimum

time for beginning decommissioning operations. In this case, parameters such as field

economics, technological innovations, logistics and market parameters, among others, should be

included as variables.

Appendix B.2. suggests an activity sheet to assist in the calculation of decommissioning

costs in areas where decommissioning activities are non-existent or just beginning.

Consulting Work Generate Economic Selecting Preferred - Mxlels - &reening r-

& Identify Options (Taildo'Ml Scenarios)

Tai!do'Ml. Scenario(s)

I I

Develop/ Select Best :l\.1ahodology

I

I I Develop I Select Best Develop I Select Con-

:l\.1ahodology tracting Strategy

I I I

Cost

Figure 3.20. Decommissioning Study Execution Flowchart (HUGHES and FISH, I 999) -modified.

86

TABLE 3.14. US MMS DECOMMISSIONING ESTIMATES FOR OFFSHORE CALIFORNIA

Platform Size Small Medium Large Ultra-Lar e

Location Offshore California


Difficulty No complications Minor Complications Major Complications

Water Depth (meters) < 121

122-244 245-366

HLV Lift Capability (ton) 500 (100 days) 2,000 (200 days) 4,000 (200 days) 4,000- 5,000 (200 days)

Water Depth (meters) 61 122 213 366


Water Depth (meters) < 91 (+ 10% contingency) > 91 (+ 15% contingency) Source: MMS (1999b)

Engineering and Planning Cost Estimation($)

200,000 400,000 600,000

1,400,000 Permitting and Regnlatory Compliance

Platform Preparation

Cost Estimation ($)

175,000 to 300,000

Cost Estimation ($)

300,000 480,000 900,000

1,200,000 Well Plngging and Abandonment

Condnctor Removal

Cost Estimation ($)

63,300 95,500

192,400

Cost Estimation ($) 21,900 34,400 59,400

Mobilization and Demobilization Cost Estimation ($)

450,000 5,400,000 8,280,000

11,160,000 Platform and Strnctural Removal

Transportation and Disposal

Cost Estimation ($)

3,960,000 15,263,000 21,450,000 48,675,000

Cost Estimation ($) 2,050,000 3,850,000

11,000,000 25,200,000

Site Clearance and Verification

87

Cost Estimation ($)

244,200-521,400 590,700- 1,060,400

TABLE 3.15. COMPARATIVE COST ANALYSIS: OFFSHORE CALIFORNIA & SOUTHERN NORTH SEA

Decommissioning Cost estimates for offshore California Percentage breakdown1

Decommissioning Activity Low Estimate High Estimate

Cost % Cost

Engineering and Planning $200,000 $1,400,000

Pennitting $175,000 8% $300,000

Platform Preparation $300,000 $1,200,000

Site Clearance $244,000 $1,060,000

Well Plugging and Abandonment $955,000 9% $6,016,000

Conductor Removal $219,000 6%

$3,802,000

Pipelines and Power Cables $404,000 $5,482,000

Mobilization and Demobilization $2,700,000 24% $11,160,000

Decks and Jackets $3,960,000 35% $48,675,000

Transportation and Disposal $2,050,000 18% $25,200,000

Total $11,207,000 100% I 04,295,000

Decommissioning Cost in the Southern North Sea Oil and Gas Province Percentage break down according to Foster Wheeler and Tecnomare 2

Description

Mobilization and Demobilization of Marine Vessels

Plugging and Abandonment of Platform Wells

Plugging and Abandonment of Subsea Wells

Topsides Decommissioning and Preparation for Removal

Topsides and Jacket Removal

Pipeline abandonment in situ & otber subsea work

Overall field decommissioning support

Onshore Dismantling & salvage

Main Contractor Engineering & design

Owner costs

Contingency 10%

Source: MMS (1999b). Total

% of Total Cost

4.5%

6.0%

3.2%

14.1%

34.0%

12.3%

4.3%

0.7%

4.0%

7.9%

9.0%

100%

%

4%

6%

9%

II%

46%

24%

100%

2 Source: HUGHES and FISH (1999). This breakdown is specific to a particular gas field in tbe NS but proportions are considered reasonably typical for otber Southern NS fields

88

TABLE 3.16. GENERAL CHRONOGRAM FOR ONSHORE CLOSURE- THE PHASED APPROACH

Activity

3.13. DECOMMISSIONING DISCUSSION

Since oil companies have a fair amount of time before decommissioning operations begin,

considerable attention should be given to strategic planning in order to minimize liabilities and

costs. Decommissioning should not be viewed as an isolated phase at the end of the project, but

instead, planning should take place as oil recovery progresses. Decisions made during all phases

of the project will, in some way, impact the decommissioning process. For this reason, planning

must always be reviewed and updated. Although uncertainties are considerable, this approach

should allow cost reduction, improved safety, and sound environmental decisions.

Incentives should be provided to ensure ever-improving technologies, addressing needs

and aspirations of all stakeholders, and, mainly, ensuring that the industry is able to comply with

all ex-post obligations. As illustrated on Figure 3.21, aiming at reducing environmental costs,

energy expenditure, and risk of contingencies, a 5 R's approach is proposed for the oil industry.

This approach is analogous to the traditional 3 R's approach (reduce, reuse, and recycle).

Accordingly, bonding mechanisms should be used to generate incentives for:

• Reduction - lessen the number of needed installations through rethinking concepts and

approaches (i.e. platformless field developments);

• Reengineering - during project planning, set as a priority, tbe design of

decommissionable facilities, the application of new concepts and approaches, testing new

materials and technologies (i.e. minimal facility approach, Maureen Platform);

• Reuse - consider the use of redundant installations and equipment, and stimulating the

expansion and improvement of a reutilization economy (i.e. adaptations yards, brokers,

etc.);

89

• Rigs-to-Reef - opening dialog with key stakeholders and academic institutions for the

consideration of an artificial reefs program, allowing the reduction of decommissioning

costs and creating artificial habitats to improve fish recharge in overfished areas;

• Recycling - establishing academic partnerships and creating incentives for the expansion

and improvement of the recycling industry, and the research of recycling technology and

application of recycled materials.

Decommissioning has become an all-inclusive, politicized, and costly issue. Experience

shows that, mainly in stringent regimes, transparency and communication are crucial in dealing

with the general public and interest groups, addressing the needs and aspirations of all key

stakeholders (Figure 3.22).

An ideal decommissioning assessment report must include effect of all possible

decommissioning options including energy use, biological and ecological impact of discharges,

secondary emissions to air, physical and habitat matters, fisheries, waste management, littering,

drill cuttings deposits, free passage, safety of personnel, national services, employment, cost

feasibility, and impact on local communities, including visual interference, noise, odor, and

traffic. The "public relation environment" may be looked at before the "physical and legal

environment". A company may strictly follow all regulations and scientific reports, and still be

far from satisfYing public aspirations.

90

SCALE OF DECOMMISSIONING EXPENDITURE

Figure 3.21. Environmental character of the proposed 5 R's Approach.

I I

Production Begins

Field 1 Development 1 plan

"Zr: -o z_ zu :5<( 0.. !!! t-+" o<= w!l! .., ., o~

a::!!:. 0..

Conceptual: Assessmem

I I I I I I I

Production Ends

T Decommissionable .. desian

............... Public Communication~

• Residual value assessment T Decommissioning planning.

Decommissioning

..... _...

Decommissioning project

Figure 3.22. Pre-project decommissioning planning for stringent regimes.

CHAPTER IV- FINANCIAL ASSURANCE SYSTEMS: BONDING MECHANISMS

How to ensure that all ex-post obligations will be satisfactorily met, safeguarding public

economic interests by maintaining investments in the sector and, at the same time, providing

guarantees against negligent lessees and eventual economic and natural contingencies? Answer:

Establishing a financial assurance regime (a peiformance bond regime).

4.1. ENVIRONMENTAL COSTS

Environmental cost is one of the many different forms of costs petroleum projects face as

they provide oil and gas to supply society's needs. Today, environmental performance is

essential for the success of a project and for the survival of oil companies. As indicated by EPA

( 1995b ), Environmental costs and performance deserves management attention for the following

reasons:

• Business decisions may significantly reduce or eliminate environmental costs;

• Environmental costs may be hidden in the overhead accounts or otherwise unnoticed;

• For instance, oil companies have discovered that environmental costs can be offset by

generating revenues through sale of equipment, waste by-products, recycling, and

even redundant structures;

• Improved management of environmental costs may result in enhanced environmental

performance and significant benefits to human health, safety, and business success;

• Understanding environmental costs and performance of processes and products may

allow more accurate costing and pricing of products and can help companies in the

design of more environmentally preferable operation alternatives, processes, products,

and services;

• Because of the new public environmental consciousness, competitive advantage with

costumers can be obtained by oil companies that can demonstrate to be environmental

referable;

• Accounting for environmental costs and performance can support a company's

development and operation of an overall environmental management system. Such a

system is today a necessity for companies engaged in international trade due to the

92

establishment of the international consensus standard ISOs, developed by the

International Organization for Standardization.

EASIER TO MEASURE

REGULATORY: i.e. BONDS

UPFRONT: i.e. INSTALLATION

BACK-END: i.e. DECOMMISSIONING

VOLUNTARY: i.e. MONITORING

MORE DIFFICULT TO MEASURE

Figure 4.1. Cost Categories, deggree of difficulty, and examples of potentially hidden environmental costs.

The definition of environmental cost will depend of bow a company intends to use the

available information (i.e. cost allocation, capital budgeting, process/product design, other

management decisions) and the scale and scope of the exercise. Figure 4.1 indicates several

examples of environmental costs incurred by companies including the relative degree of

difficulty in approaching each category. Figure 4.2 shows an additional classification criterion

with respective examples of costs involved in projects.

The main environmental cost categories, according to EPA (1995a), are described as

follows:

• Conventional costs: costs of using raw materials, utilities, capital goods, and supplies .

Although not usually considered as environmental costs, they may sometimes be

overlooked in business decision-making.

93

• Potentially Hidden Costs: costs that may be potentially hidden from managers (i.e.

upfront environmental, regulatory, voluntary, and back-end costs).

• Contingent Costs: costs that may or mat not be incurred in the future. Such costs may

be illustrated in probabilistic terms (expected values, ranges, probability of exceeding

some amount, etc.).

• Intangible costs: costs incurred voluntarily for environmental activities and

operations. The costs themselves are not "intangible", but the direct benefits often are.

A discussion on environmental costs and damages is presented on Chapter II and three

broad categories of environmental damages are proposed (accidental, continuous and ex-post).

4.2. REGULATORY APPROACHES: COMMAND AND CONTROL VS. ECONOMIC

INCENTIVE

The sustainability concept asserts that oil and gas exploration and production activities

should not compromise future environmental quality. There are two main approaches in

regulating environmental issues: (!) command and control mechanism (command system), and

(2) market-based economic incentives (incentive system or market mechanism).

The present environmental scenario, a result of the continuous application of the

command and control approach, shows the inefficiency of this approach in protecting the

environment. The main causes are pointed out by CORNWELL and COSTANZA (1994) and

adapted below to the oil sector:

• The great uncertainties involved in calculating end-of-leasing costs (i.e. contingencies,

liabilities, and future operation costs).

• The costly and lengthy processes involved in trying to collect funds from liable

companies through litigation.

• It treats projects homogeneously not taking into consideration type of platforms,

installation settings, company's records on environmental performance, financial history,

regulatory compliance record, etc.

• It places a great information burden on the regulatory agency (i.e. determining the best

available technology for platform decommissioning and well abandonment, monitoring

and enforcing penalties in cases of noncompliance, etc.).

BIBUOTECA CENTRAL 94 St"'"'. A- 0 r1 '' - ':-· \.?. v

• It defines the use of a particular technology for the removal and disposal of offshore

installations, and for capping, plugging and abandonment of idle wells. If a specific

technology is enforced, there is no incentive for the development of innovations that

could result into improvements and cost reduction.

• It motivates regulatory evasion rather than regulatory compliance.

• It usually presents vague regulatory language, which offers companies the opportunity

to build persuasive cases by showing, for instance, that certain decommissioning or

abandonment requirements are unachievable.

Governments, which are responsible for producing and implementing regulations, were

forced to come up with mechanisms that would guarantee the availability of financial resources

in case of contingencies and/or insolvencies; otherwise, government would cope with

environmental ex-post costs. For this reason, authorities have been promoting alternative tools to

control environmental damages (SHOGREN et. al., 1993; TIETENBERG, 1996; DIETZ and

VOLLEBERGH, 1999).

YOUNG et al. (1996) has indicated several benefits produced by market-based

mechanisms for the general productive sector. Nevertheless, to the upstream petroleum sector, in

theory, the merits of market-based mechanisms are their ability to:

• Influence behavior through price signals without the need for direct intervention in the

affairs of oil companies;

• Encourage oil companies and operators to seek the most cost effective (and often

innovative) solutions to environmental problems;

• Decentralize decision making to companies and operators who often have better

information on how to solve such problems than government or agency authorities;

• Reduce agency's enforcement costs as well as the industry compliance costs;

• Provide the upstream petroleum industry ongoing incentive to develop better

environmental approaches.

According to CORNWELL and COSTANZA (1994), the incentive approach encourages

the distribution of responsibilities among all stakeholders, decentralizing the decision-making

process on their own interest, in order to protect and rehabilitate the environment, while the

95

applicable authority would be responsible for providing economic incentives to encourage a

determined behavior, defining performance objectives rather than a course of action. Figure 4.3

indicates key stakeholders and their main interest in bonding mechanisms.

MILLER (2000) indicates that, presently, many governments routinely require the use of

enviromnental financial assurance instruments to guarantee environmental performance during

different stages of the mining cycle (exploration, development, operations, closure and

reclamation).

Indeed, incentive mechanisms allow better economic efficiency than traditional command

approaches leading to better results, as demonstrated in the US coal mining sector, US

govermnent construction works, collection systems for beverage containers, lubricating oil,

automobile batteries, and tires (CORNWELL and COSTANZA, 1994; ANDERSON and

LOHOF, 1997). In the upstream offshore petroleum sector, the application of incentive

mechanisms is relatively recent.

The most cormnon incentive approach used in the oil sector is the financial assurance

system (bonding system), which is designed to ensure compliance with all ex-post environmental

obligations (abandomnent, clearance and decormnissioning requirements), providing and

enforcing conditions of negligible health and safety risk to local inhabitants, and safety for

navigation and the enviromnent. Worldwide, several countries are adopting, or in the process of

adopting, financial assurance requirements. A number of natural resources agencies, petroleum

and mining, have already established some form of bonding system aimed at ensuring the

performance of ex-post environmental obligations (FERREIRA et al, 2003a). These systems can

be found in operation in the United States, Canada, the United Kingdom, Australia, Brazil, the

Philippines, Fiji Islands, New Zealand, and Sri Lanka, among others (OSM, 1987, 2001; GAO,

1994; YOUNG, et al. 1996; AEP, 1996, 1997, 1998a, 1998b; CANADA, 1996; JAMES, 1997;

ADB, 1997; RANASINGHE, 1998; NIUMATAIWALU, 1998; HORESH, 1998; FERREIRA

and ALVES, 1998; AEP, 1998a, 1998b; RYAN, 1998; HESS, 1998; BRYAN, 1998;

CORNWELL and COSTANZA, 1999; WEBSTER, 1999; MMS, 2000d; DTI, 2000a, 2000b;

GERARD, 2000; FERREIRA and SUSLICK, 2000; MIRABELLA, 2000; BAIER, 2000;

STOKES, 2000; UNICAMP/CEPETRO, 2001; ANP, 2002a). Some countries such as the United

States tend to move forward with new rules aimed at strengthening bonding requirements

(BOYD, 2001).

96

Regnlatncy Notification Reporting Monitoring/testing Studies/modeling Remediation Record keeping

Training Inspections Manifesting Labeling Preparedness Protective equipment Medical surveillance Environmental insurance

Spill response Stormwater management Waste management Taxes/fues

Corporate image Relationship w/ customers Relationship w/ investors Relationship w/ insurers Relationship w/ professional staff

Ilpfmnt Site studies Site preparation Permitting Research & Development Engineering & procurement Installation

Conyentjonal Costs Capital equipment Materials Labor Suppliers Utilities Structures Salvage value

Back-End ClosurefDecommissioning/ abandonment Disposal of inventory Post-closure care Site survey

Relationship w/ workers Relationship w/ suppliers Relationship w/lenders Relationship w/ host communities

Figure 4.2. Examples of environmental costs (EPA, 1995 -modified).

4.3. THE BONDING SYSTEM IN THE OIL INDUSTRY

Yolnntacy Community relations/ outreach Monitoring/testing Training Audits QualifYing suppliers Reports Insurance Planning Feasibility studies Research & Development Habitat protection Landscaping Other Environmental projects Financial support to environmental groups and/ or researchers Philanthropy

Relationship w/ regulators Relationship w/ researchers Relationship w/ academic institutions

The bonding system can be used to operationalize the sustainable development concept.

Companies wishing to explore and produce hydrocarbon resources would be required to post a

bond in advance equal to the best-cost estimate for ex-post operations. Therefore, before a

company is granted licenses or permits to drill, deepen, or alter a well, and before a platform is

installed at sea, a bond must be posted to cover all plugging, abandonment, and decommissioning

obligations.

97

In practice, the merits of bonding systems in the upstream petroleum sector are difficult to

be demonstrated, mainly due to lack of empirical evidence. According to W AELDE (1995), the

difference between instruments of public policy is not always easy or clear and may often merely

indicate the choice of a specific format rather than a difference in substantive policy. Most

bonding systems used in the oil sector are not self-enforcing and may involve considerable

control costs YOUNG et al. (1996). Bonding instruments used for guaranteeing the performance

of ex-post obligations in the oil sector are a hybrid of market mechanisms and command and

control regulations. As mentioned before, the ideal market mechanism would allow a firm

flexibility in the extent to which it performs closure operations, but force it to pay for all social

costs it imposes (including environmental costs). Such a system takes advantage of the firm's

internal knowledge of production costs, clean up costs, and profits. When closure is more

expensive than social costs, the firm pays its social costs. When closure is less expensive, the

firm performs closure operations. Most important in the dynamic setting, there is always an

incentive to seek new technologies and techniques that minimize environmental costs. In the

case of bonds, the regulator must determine the closure standard and is therefore less able to rely

on the firm's internal knowledge. However, in a number of ways, financial assurance does help

improve market function (FERREIRA et al, 2003a).

Even though obligations such as decommissioning operations may represent up to I 0%

of a project's total investment, quantitative studies on the potential impacts of such policies are

rare. The academic interest in such approach is relatively recent and available references in the

literature are scarce. This is a rather interesting scenario, since the application of bonding

mechanisms has a great potential to severely impact the profitability of offshore projects. Some

instruments require the anticipation (upfront security requirements) of 100% of ex-post

environmental costs, even before projects produce revenue.

An evident change of attitude is corroborating to the worldwide implementation of

incentive approaches. In a not so distant past, the industry in general, would view any obligation

to provide financial securities to guarantee ex -post environmental obligations as "lost

investment". Companies used to look primarily for immediate low cost solutions. Presently, the

industry acknowledges that public image has a great value in today's economy.

With increasing public awareness, pressure from interest groups and the politicization of

ex-post environmental issues, it is becoming rare for an oil project to obtain leasing concession or

98

operating license without the provision of some means of financial security to indeiilllifY

governments against ex-post environmental costs. Authorities are increasingly looking for ways

of eliminating liabilities before licenses and permits are issued. It seems only reasonable to

suggest that such trend may soon arrive in new developing frontiers. For instance, ANP is in the

process of preparing a set of end-of-leasing regulations, which in the near future could include

performance bond mechanisms. Currently, ANP requires a form of financial bond, an

irrevocable stand-by letter of credit, in the bidding process (ANP, 2002a).

ulators

Industry

Society

lcFtnartcial & Environmental Liabilities

Investment Flow

Profitability Image

Development

Profitability Image

New Business Risk Reduction

Figure 4.3. Key Stakeholders involved in the bonding process.

Bonds are financial instruments that can come in several forms with unique attributes and

requirements, as descnbed in Chapter II. All forms of bonding instruments must be (I) pledged

to the regulatory agency and (2) kept in good standing during the entire life of the project.

A comprehensive description of financial instruments used as bonds in the upstream oil

sector can be found in BLM (1995, 1996), MMS (2000d), and UNICAMP/CEPETRO (2001).

Other key references are not directly aimed at the upstream petroleum sector, but do provide

substantial infonnation on instruments used as financial guarantee (YOUNG et al., 1996;

CORNWELL, 1997; EPA, 1997; BRYAN, 1998; MILLER, 1998; APOGEE/HAGLER BAILLY

WITH D. R. ANDERSON ASSOCIATES, 1998; NWF, 2000; OSM, 2000b; NWF, 2000).

99

4.4. BONDING COSTS

It is acknowledged that the cost to meet technical and bonding requirements for ex-post

environmental obligations will impact companies differently. Such impacts can be direct

(premiums, fees paid to surety companies, fees associated with third-party securities and

requirements, interest earned in cash deposit in escrow accounts, etc.) and/or indirect (increase or

reduction of government earnings trough corporate taxes and other participations, improvement

of accumulated funds on savings-undersupplied economies, reduction of the company's

borrowing capacity, increase in the cost of credit, etc.). MILLER (2000) indicates that the

amount of capital tied up in security is enormous.

Successful application of bonds will depend upon form of bonds, type of projects and

companies, and scenarios. Usually large and fmancially healthy companies are not significantly

affected by bonding requirements though marginal projects operated by large companies may be

severely impacted. On the other hand, small companies operating small and marginal fields tend

to be severely affected.

Authorities must pursue flexible and optimum solutions; on the contrary, smaller

companies will be driven out restricting the sector. It may be the intension of some regulatory

environments to drive out companies that cannot provide adequate guarantee. Other regimes may

be interested in improving the competition within the sector by offering flexible mechanisms and

being more sensitive to financial impacts of bonding policies on small companies. Some

agencies, with a longer bonding implementation history, have developed more complex bonding

regimes allowing incentives for companies with good history of environmental compliance,

credit record, decommissioning experience, etc.

In Chapter II, two major bond categories were identified in terms of specific purpose: (1)

fmancial bond, a bond that guarantees the payment of a specific amount determined by the

agency in case of noncompliance; and (2) performance bond, a bond that guarantees the

performance of a contractual obligation. Performance bonds indemnify authorities against

operation costs, safeguarding agencies against both technical and financial failure, and premature

or unplanned decommissioning (Figure 4.4). A financial bond does not guarantee the

performance of an obligation. Instead, it can be compared to a token pledging, under the penalty

of loosing no more than the amount bonded, the candidate's intention of keeping all fmancial

commitments (e.g. timely payment of royalties and rents, honoring bids, etc.).

100

4.5. SETTING THE BOND AMOUNT AND DURATION

Determining the amount to be bonded is probably one of the greatest predicaments

involving the bonding system. Due to inadequate bonding estimation, many problems were

caused in the past when mining companies became insolvent and the bond in place was not

sufficient to cover abandonment/rehabilitation costs; for instance, the well known Uranium

Mines Episode in Western USA (COLLINS, 1991).

r

••••••••••••••••••••

Figure 4.4. Typical cash flow for oil projects. Provisions for premature and unplunned decommissioning operations. Ex-post provisions brought up as up front costs making funds available even in case of technical. financial failure, or premature and unplanned decommissioning.

The determination of the amount and duration of performance bonds is based on: (I) the

nature, extent, and duration of the proposed project; and (2) the magnitude, type, and estimated

closure cost. Bonds must be maintained in good standing for the duration of the project,

remaining in effect until all ex-post obligations have been successfully completed. Authorities

will then release the bond.

Usually, authorities set the bond based upon the company's closure cost estimate plus

profit and overhead, which represents the third party cost to complete operations in the event of

forfeiture. Ideally, cost estimation should consider a worst -case damage scenario, or the highest

101

estimated operation cost to complete ex-post closure operations. In this case, if a company were

able to demonstrate that the damages to the environment or costs to complete ex-post closure

operations are less than previously estimated, the difference would be refunded to the company.

In case of under-performance of ex-post operations or forfeiture (due to insolvency,

negligence, etc.), the bond would include sufficient financial resources to repair, cover all

damages, or complete operations. In any of these cases, there would be possibility for refunds.

The practical result is that the motivation for properly completing ex -post obligations and

investing in new technologies comes now from oil companies and not from authorities, public, or

interest groups (FERREIRA, 1999).

For US offshore projects, the required bond amount varies significantly from state to

state. Public interest plays an important role in the definition of such amounts. Some states are

more interested in safeguarding future investments than guaranteeing the proper abandonment of

future wells. Other states will set very high bonds in other to lower the risk of environmental

damage, and keep risky parties away, as it is the case in the State of Alaska (Table 4.1.).

TABLE 4.1. US BOND REQUIREMENTS FOR ONSHORE PROJECTS

State

Alaska Arizona California

Inactive well New Mexico

Ohio Pennsylvania

Tennessee

Bond starts at (US$)

100,000

10,000

10,000

5,000 7,000

5,000 5,000

2,000

Source: MCFADDING (1996)

Blanket bond starts at (US$)

200,000

25,000 100,000

100,000

50,000 15,000

25,000

10,000

In reality, it is very unlikely that a disturbed area will be able to be truly restored. Most

extractive activities produce and trigger irreversible damages, and users can only reduce impacts,

mitigate problems, and rehabilitate the area for future uses or conservation. Rehabilitation

objectives must be rigorous but, at same time, realistic. Two good reasons why regulators should

not compromise are:

• Future impacted communities will not spare the agency and litigious actions will be

inevitable.

102

• Stringiness of regulations provides excellent incentive for technological innovations,

allowing better environmental results and lower ex-post environmental costs.

Regarding setting the appropriate bond amount, experience shows that lax requirements

do not encourage compliance and strict requirements encourage evasion; lenient requirements are

ignored and stringent are disobeyed. An optimum ground must be pursued.

Ex -post standards and requirements should not be definite. The petroleum sector is

extremely dynamic (new equipment, new technologies, new frontiers, etc.). Regulators must

recognize the value of changes and be alert to identifY over-regulations.

Ideally, bond requirement should be based on the cost for the rehabilitation of the entire

lease area, applying the present value of all ex-post operation costs. There are three main

methodologies for defining performance bond amounts for offshore projects:

• 100% of ex-post costs+ (plus) indirect costs:

• 100% of ex-post costs * (times) risk rate:

• 100% of ex-post costs+ (plus) worst-case scenario:

During the preparation of this present work, several approaches for calculating bonding

requirements were identified. The following briefly describes some of the most common

methodologies currently applied:

1. By the lessee - the company defines all ex-post operation costs and the bond amount is based

on this estimate. Accepting this approach provides low regulatory costs for the agency.

However, regulators become susceptible to inaccuracies and deceitfulness. Most certainly,

lessees will tend to underestimate ex-post costs and ignore indirect costs. Historically, it is

possible to verifY that the liability (financial, environmental and legal) of successive

misestimated projects is disastrous. To avoid this situation, contracting the services of

independent specialists could be a short-term solution for the agency. In the long run, the

agency should work at constructing a comprehensive database system. Some agencies try to

minimize direct involvement and maximize public scrutiny. However, this approach is

mostly suitable to societies that historically coexist with the extractive sector, knowing all

103

related socioeconomic benefits and burdens, and where a mature and transparent

population/industry relation has been historically achieved.

2. By the lessee and agency - the lessee submits a closure plan that is either approved or

modified by the agency, which will establish a bond amount. In this case, the agency must

rely on a group of ex -post operations experts in order to evaluate, and, if necessary, revise the

proposed plan and define the bond requirement.

3. By the agency - the agency owns a control system, usually a comprehensive database, and

establishes bond requirements based upon its own knowledge of ex-post costs.

4. By independent certified experts - in this case, independent and certified specialists would

evaluate the ex-post plan along with cost estimation proposed by the lessee, and produce a

teclmical report recommending a bond amount. Authorities must not presume that

independent experts will share the experience being acquired. There is a strong financial

motivation for not happening so.

Some critics say that regulators have a possible tendency to overprotect themselves from

all possible liabilities, even the more remote ones, leading to unreasonable high-cost bond

requirements. Probably, the conciliatory attitude should be testing the sector, balancing the need

for demonstrating financial capacity with the necessity for keeping a competitive and attractive

sector. Excessive direct costs upon the industry may represent the redirection of important

investments to regions that offer better profit margins. In this case, the agency walks on a very

thin line between public pressure for stringentness and industry pressure for flexibility (Figure

2.3).

4.6. FORFEITURE AND BOND RELEASE

A bond may be subject to forfeiture for different reasons: (!)if a well or installation has

been abandoned or temporarily closed without initiating required procedures; (2) if a company

fails to meet ex-post obligations in accordance with the approved plan; or (3) if a company fails

to maintain the amount bonded (MCELFISH et al, 1996; FERREIRA et al, 2003).

104

After the successful completion of all closure requirements, authorities must provide

release from all bonds. If ex-post-related activities are being conducted concomitantly during the

life of the project and if activities are satisfactory completed, authorities may also authorize the

proportional release of bonds.

4.7. THE BONDING SYSTEM STEP-BY-STEP:

1. Bonding system dynamics:

• Submission of a detailed exploration plan to the regulatory agency.

• Definition of the bond amount by the regulatory agency.

• Fulfillment of bond requirements (providing the bond).

• Exploration.

• Submission of a detailed development, production, and decommissioning plan to the

regulatory agency.

• Reevaluation of the bond amount by the regulatory agency.

• Fulfillment of new bond requirements (providing the bond).

• Operation and ex -post obligations (i.e. decommissioning).

• The bond is released and, if this is the case, refunded to the oil company.

2. Main positive bond effects (Figure 4.5)

• Decentralization of the decision process.

• Performance objectives are defined rather than establishing a protocol of action to be

strictly followed.

• Incentive to the development of technological innovations with the objective of

improving decommissioning results and reducing costs.

• It guarantees the availability of funds to cover the costs of all ex -post obligations

• It eliminates long and costly litigious battles.

• It motivates the internalization of contingency costs, stimulating the monitoring of the

consequences of each decision made.

105

• Companies begin to assume the ex -post burden in order to demonstrate that end-of

leasing obligations will be met as contractually required, transferring the financial risk

from the potential victims (government and taxpayers) to oil companies.

• It safeguards authorities from techuical and financial risks, providing funds for eventual

premature or unplanned closures.

3. Some bond definitions:

• Performance bonds: mechanism used to guarantee performance requirements.

• Financial bonds: mechanism used to guarantee financial obligations.

• Blanket bond (areawide): mechanism used to cover an area with several wells and

installations.

• Bond Pool: a consortium of small producers established to reduce and spread inherent risk

in offshore oil projects.

• General Bond: bonding general requirement for all companies, usually less significant

bond amounts (financial bonds).

• Supplemental Bond: additional bonding requirements based on a company's risk

assessment model (environmental, techuical, financial and compliance risks).

Supplemental bonds can comprise both fmancial and performance bonds. Figure 4.6

indicates the risk evaluation of a candidate lessee. Figure 4. 7 shows the calculation

matrix for the risk evaluation data obtained in Figure 4.6.

4. Bond-calculation Parameters:

• Estimated ex -post costs.

• Estimated contingency costs (only related to ex-post operations).

• Plarming and engineering costs.

• Third-party profit and overhead costs.

• Management, inspection, and supervision costs.

106

Environmental performance during

the project (Continuous damages)

Environmental Contingencies during

the project (Accidental Damages)

Environmental Obligations under a Leasing Contract

INTERNALIZATION OF ENVIRONMENTAL COSTS:

(Environmental Performance Improvement) +

(Contingency Reduction: quantity and magnitude) =

Lower Ex-post Damages

Project Value Maximization

Figure 4.5. The bond effect. Bonding requirements acting over the internalization process, assisting in the reduction of accidental and continuous environmental damages, and maximasing project value.

107

5. Reasons for Recalculating Bond Values (increment or reduction):

• Changes in the parameters used to calculate the bond amount.

• Changes in the economic scenario .

• Signs suggesting problems in the operating company .

• Changes in the technical and financial credibility of the oil company .

• Changes in the fmancial capability of the oil company; its capacity to fulfill existing

financial obligations is being questioned in the market.

• Changes in the estimates of proven reserves within areas leased to the company.

• Changes in the credit record ofthe company.

• Changes in the compliance record of the company (moral risk).

6. Main Bond Obligations:

• All Bonds must be previously approved by the regulatory agency.

• All bonds must be payable to the regulatory agency.

• All bonds must be sufficient to guarantee all ex-post obligations.

• All leased areas must be bonded.

7. The Regulatory Agency is Responsible for:

• Monitoring all bonding instruments.

• Monitoring eventual market value variations of issued bonds (market value).

• Monitoring institutions that issue notes, securities, collaterals, and other assurance

instruments.

8. A bond may be Forfeited due to:

• Legal reasons.

• Technical reasons.

• Financial reasons.

108

NO SUPPLEMENTAL BOND

REQUIRED

OFFSHORE OIL PROJECT

GENERAL BOND REQUIREMENT

SUPPLEMENTAL BOND REQUIREMENT

(Financial to Performance Bond)

NO RISK

LOW RISK

RISK

I I I I

NoR~~---1---~!~--J

RISK ASSESSMENT MATRIX

BOND VALUE

Step 1: Detennination of proposed project's risk

Step 2: Scoring for environmental/financial/ technologic/compliance risk

Step3: Plotting scores on matrix in order to detennine the percentage of estimated bond amount

Figure 4.6. Risk Assessment Model. Based on AEP (1998a) proposal fur mining reclamation bonds, here adapted to the oil industry. In this case, the performance bond requirement is set based on risk offered by the candidate.

109

9. If a bond is forfeited, the agency will:

• •

•

Collect the value of the forfeited bond .

Use the bond to fund a third-party, a contractor, to update and/or correct the project in

accordance to the proposed closure plan.

Return funds in excess to the company .

4.8. DIFFERENT FORMS OF BONDING INSTRUMENTS

Traditionally, bonding instruments have been used to provide different forms of

guarantees as shown below: fidelity bonds (guarantee of honesty); fiduciary bonds (guarantee the

proper management of assets); judicial bonds (guarantee the compliance with judicial decisions);

and contractual bonds (guarantee the fulfillment of contractual obligations) (ROWE, 1987;

JOHNSON, 1986; YOUNG et al., 1996; CORNWELL, 1997; CORNWELL and COSTANZA,

1999; MILLER, 2000, UNICAMP/CEPETRO, 2001). The category "Contractual Bonds"

includes several subcategories including: performance bonds; construction bonds; bid bonds;

service and materials bonds; advanced payment bonds; retention bonds; maintenance bonds;

transport bonds; government regulatory bonds; customs bonds; financial bonds; and license and

authorization bonds.

As mentioned before, within the Exploration and Production sector, two major bond

categories can be identified in terms of specific purpose: financial and performance bonds. Both

fmancial and performance bonds may be used several times within a single contract. Under some

regimes, companies acquiring oil or gas leases are required to post a preliminary financial bond

(a fixed and relatively small bond) guaranteeing fmancial aspects of the lease contract (regular

payments of rents and royalties, civil penalties, fines, etc.). Usually, companies holding more

than one lease may opt for a mechanism called "Areawide Bond", or "Blanket Bond", in which

case, a single bond would cover multiple leases.

In addition to fmancial bonds, some regulatory agencies require a performance bond,

which is usually based on the best-cost estimate for completing ex-post operations under the

established lease contract. Performance bonds serve individual projects and individual wells.

Multiple performance bonds may be found within a lease, but a single performance bond carmot

be used to cover multiple projects.

110

Bonds must be maintained until leases are terminated or transferred and until ex-post

obligations are satisfactorily met. If closure activities are being conducted concomitantly during

the life of the project, the phased approach, authorities may authorize proportional releases of the

bond.

75%

.lie

.~ 1------------------- ---------------------~ 0::: -.!!! 1.1 1::: ca

50%

100%

/ •/

#

/ .~/ ~/' /

#

/ /

.s ~----------~~--# LL. 100%

25%

#

/ /

#

25%

/ 75%

50%

Environmental Risk Figure 4.7. Risk Assessment Matrix

#

Definitions and descriptions of currently used bonding instruments can be found in the

following publications including CORNWELL (1997), FERREIRA and SUSLICK (2001), OSM

(2000b), NWF (2000), ANP (2001), UNICAMP/CEPETRO (2001), and FERREIRA et a!.

(2003a). As explained on Chapter II and illustrated on Table 2.4, a classification was proposed

in to facilitate the systematic evaluation and optimum applicability of each financial instrument.

The present study was able to identny the following financial instruments, which are briefly

described below. Descriptions are based on information obtained on the following publications

and interviews with specialists (MCELFISH, et a!, 1996; MCF ADDING, 1996; ISO, 1997;

Ill

BOLENDER, 1998; HORESH, 1998; AIG, 1998; BRYAN, 1999; BAIER, 2000; BRYAN, 2000;

DIE, 2000; NWF, 2000; MILLER, 2000; STOKES, 2000; WILLIAMS, 2000; OSM, 2000b,

2000c; MMS, 2000e; BLM, 2000; MIRABELLA, 2000; RADIGAN, 2000; CORNWELL, 2000;

MPC, 2000; UNICAMP/CEPETRO, 2001):

Corporate Surety Bonds (CSBs):

A surety bond is a contract involving three parties, the surety company, the oil company

or Jessee, and the regulatory agency. Sureties are issued (written) by certified financial

institutions. The surety contract guarantees the payment of funds (not to exceed the penal sum)

or the performance of ex -post activities in case oil companies fail to fulfill them. Sureties

guarantee the credit of an oil company and both parties equally share contractual obligations.

Surety companies do not expect a default scenario. However, if it occurs, the surety company

pursues reimbursement from the principal. In case of default, authorities hire an independent

contractor to perform ex-post operations. Sureties may provide extended guarantee for residual

liabilities even after ex -post obligations are finished (evergreen clauses). In order to obtain

sureties, candidates must go through a rigorous underwriting process, which will access their

financial, technical and moral capacity. The underwriting process makes it difficult for small or

newly formed companies to obtain surety bonds. In the United States, the US Treasury defines a

maximum coverage amount (a form of government reinsurance) and monitors surety companies.

Surety bonds are analogous to insurance policies in that companies pay annual premiums

and fees to keep the bond in place. The main difference between sureties and insurance policies

(and annuities) is that a surety guarantees the credit of an oil company, and an insurance policy

transfers the liabilities to the insurer.

Each surety company follows its own financial criteria to judge a company and determine

premium rates (i.e. net worth level, credit rating, decommissioning experience, etc.). More

commonly, premiums are defmed according to the fmancial risk and project characteristics.

Currently within the oil sector, surety premiums are usually paid annually; for instance, $12.50

per $1,000 per year, or 1.25%, but it may get up to 3.00%. Under most regimes, as it will be seen

in Chapter V, premiums and fees are allowable against tax (deduction rates vary significantly).

Because of such high stakes, some bonding companies will not write this class of instrument for

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the oil industry, only larger broker houses or larger surety companies (BOLENDER, 1998;

FERREIRA and SUSLICK, 2000; DIE, 2000).

Sureties are non-cancelable, even if the contracting company fails to pay premiums and/or

in the event of bankruptcy or insolvency. One of the main advantages of this instrument is that

no upfront funds are required. If companies remain solvent and conclude required operations,

bonds are released and premium payments cease. The contracting company still has to disburse

out-of-packet funds to cover ex-post operations. In case of forfeiture, the surety company will

have to pay for all contractual obligations. In addition, under most legal regimes, further

complications may incur, including civil and criminal penalties, loss of operating license, credit,

and reputation damage, etc. (FERREIRA and SUSLICK, 2000).

Some surety companies offer a combination of sureties with a trust fund, but most of the

times, sureties are sufficient to demonstrate fmancial guaranty. Since it may be difficult for some

small and newly formed companies to obtain a surety bond, regulators some times offer different

forms of escrow accounts so these companies are allowed to establish their credibility within the

sector, acquire experience and build up their assets. Then, companies can substitute their escrow

accounts for sureties.

Another benefit provided by sureties is that they are irrevocable, and issuers are

monitored by the Central Bank (US Treasury), reducing regulatory costs. In addition, surety

companies have a great interest in monitoring the principals, the lessees. If there is margin for

any litigious inquiry, it will be between the surety company and the principal; and regardless,

the agency will promptly receive the penal sum. Some regulators, mostly in the mining and

onshore oil sector, complain of having some difficulty in collecting money from surety

compantes.

A number of specialists defend that goverrunent should provide some form assistance so

small and newly formed companies could obtain surety bonds more easily. The problem is that

such mechanism would completely armul incentives for compliance, which is the whole point of

requiring bonds. In addition, in case of default, since surety bonds are a guanmtee of credit, the

government would be accountable for the absence of credit, and taxpayers would, once more,

cope with liabilities.

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Collateral Bond (CBs):

Collateral offered by companies to provide guarantee for the completion of ex-post

obligations include: company's assets, such as cash, real estate, treasuries, instruments indicating

the presence of a line of credit or a funded account. Some collateral instruments offer interest

earnings (cash, Investment Grade Securities, Treasury securities, etc.). Other instruments require

payment of fees and premiums (Letters of Credit, etc.).

Within this category, instruments have similar attributes and characteristics and, many

times, their names are used invariably with the same meaning. Such accounts must be under the

control, for administration purposes, of a trustee other than the agency and the lessee. In some

circumstances, the agency may function as a trustee.

Paid-In Collateral Accounts or Pre-Paid Collateral Accounts (PPCAs)

There are several variations of PPCAs, but they usually work as a three-party irrevocable

agreement, where an oil company transfers funds to a financial institution (trustee) to be managed

in the name of a third party (the regulatory agency). The account must be supplied with the full

bond amount, the required guarantee, before the project begins. Funds can only be released with

the approval of the regulatory agency and the agreement cannot be altered or cancelled

unilaterally. Interest revenues may be either added to the account and paid at the end of the

project, or paid as they are earned. Allocation of cash in this manner causes significant direct

costs.

Companies cannot use the deposited collateral to fund ex -post activities. After the

successful conclusion of all ex-post operations and the release of the bond, the deposited amount

is reimbursed to the oil company. In case of forfeiture, the bond amount is used by the agency

to contract an independent operator to perform the necessary ex -post obligations. In this case,

other sanctions may be imposed.

PPCAs pay interest, guaranteeing the value of money and this instrument category is

promptly available in the market. The trustee has the power to manage the investments. An

annual fee is charged and interest earnings can also be added to the account to reduce or

eliminate future adjustments required by the agency. Currently, these accounts are rarely used

due to the availability of a variety of other less costly options.

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Allocating capital in large quantities in such way (upfront) cause considerable financial

impacts on the Jessee, allowing significant opportunity costs. In order to offer some

attractiveness, both the industry and the financial sector waits for some form of fiscal incentives

for this form of instrument. Currently, PPCAs are not tax deductible and interests earned are

taxable.

As far as regulators are concerned, PPCAs are very efficient in guaranteeing ex -post

performances, offer premium liquidity, and an excellent incentive for compliance.

Unfortunately, PPCAs require complex contracts and close monitoring of financial institutions.

This may cause some additional regulatory costs, mainly in long-term projects. In order to

reduce risks, the agency must be the only beneficiary, making it possible to regulators to

withdraw funds upon pre-established conditions.

Escrow Collateral Accounts (Escrow Agreements) (ECAs)

The difference between escrow accounts and other accounts is very tenuous, and, most

of the times, these names are used interchangeably with the same meaning. ECAs must have the

guarantee of central banks. For this reason, they must not surpass the maximum guaranteed

value established by the Central Bank. The trustee would be responsible for buying Treasury

Bonds every time the limit is reached. This mechanism may bring some form of fiscal

incentives during certain periods. Usually CDs may substitute escrow accounts.

Cash Collateral Accounts (CCAs)

This instrument falls in the same category as escrow accounts. Some agencies allow

small and independent lessees to use cash and cash equivalent (certified checks, savings

accounts, etc.) to demonstrate financial guarantee. In such cases, the accounts must be certified

by the Central Bank. In more competitive regimes, this is the only form of instrument that small

and independent operators have available to demonstrate financial guarantee. Terms of account

contract must state that funds cannot be withdrawn without the written permission of the

agency.

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External Sinking Funds (ESFs)

ESFs work as any collateral account but allowing periodic payments. In addition, this

form of instrument requires a combination of instrument guarantees. For this reason, ESFs may

take the form of different instruments available in the market. Whatever the instrument used, it

is intended to set aside resources and assets. The combination of guarantees must produce the

total amount of the bond required. As the account is being funded and the real guarantee

increased, the lessee may reduce, in the same proportion, the use of other instruments. When

the account is completely funded and requirements are completely satisfied, the ESF may be

transformed in other instruments. Advantages and disadvantages will depend on the form of

instrument assumed by the ESF. This instrument integrates the financial benefits and attributes

of interest earnings, the flexibility of periodic payments (the same as a LSCA), and the approval

of the agency (the same as a PPCA). In some occasions, a well-prepared portfolio of

instruments may offer a better scenario than a PPCA. Regulatory costs for ESFs are

considerable and managing a variety of instruments at the same time can be very complex.

Certificate of Deposit (CDs)

CDs certify that a specific deposit has been made. Certificate of Deposits are known as

debt-instruments that pay fixed interest and have a predetermined maturity (term). They can be

used as collateral for loans and demand penalties for early withdrawn. CDs can also be attached

to binding contracts between interested parties. Maturing periods vary significantly but can be

renewed automatically. CDs may be negotiable and nonnegotiable. Nonnegotiable are usually of

small face value. Negotiable CDs are usually of large denominations and can be traded in the

financial market by corporations, governments, and central banks from other countries. This

mechanism was developed throughout the history as a result of innovations within the financial

market.

CDs with variable rates, CDs rollover, and CDs that can extend the term of other CDs.

CDs can also be time-deposit and demand-deposit. Time-deposit CDs are paid only in specific

dates set by the instrument and penalizes if redeemed prematurely. Demand-deposit CDs allow

withdraws at any time after a period defined by the instrument (30 to 90 days). All CDs must be

payable or directed to the regulatory agency, and placed under the protection of the same agency

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or an independent financial agency. In case of default, the agency is authorized to liquidate the

instrument and use the funds to fulfill ex -post obligations.

This category of instruments remunerates with interests, guaranteeing the value of money.

After maturity, CDs may be redeemed by the principal value plus accumulated interests. This

instrument is promptly available to the agency, as needed. Issuing and maintaining CDs generate

direct and indirect costs to the lessee (legal fees, depreciation value, market, fluctuations, etc.).

If the CD face value is at least the same value of the costs to complete ex-post obligations,

the instrument offers an efficient form of guarantee to the agency. CDs are also efficient to

guarantee long-term closure projects. In order to reduce inherent costs, the agency should

contractually require that CDs are made payable to the agency. In such circumstances, the

issuing party must renounce all rights to pledge the CD in other contracts. CDs must not be

issued with face values higher than the amount guaranteed by the applicable Central Bank (in the

US: US$ I 00,000). CDs must be issued with a limited maturity, so they can be periodically

adjusted for inflation and submitted to revisions regarding ex -post obligation costs. CDs must be

sufficient to cover ex -post obligations even if they have to be traded before the maturity period.

If sold before maturity, CDs are traded bellow their face value. As an additional guarantee, the

agency may require a "standby" or escrow account combined with the CD, especially for long

term projects.

Salvage Revenue Collateral Bonds (SRCBs)

This category is similar to Self Guarantees. It is difficult to separate these two categories

from each other. Under this scenario, the lessee would demonstrate that the estimated value of its

salvage (platform, equipment, units, etc.) is sufficient or partially sufficient to cover ex-post

obligations.

SRCBs do not require allocation of capital, eliminating opportunity costs and direct costs.

In addition, there are not premiums or fees involved. On the other hand, SRCBs do not offer

adequate liquidity to the agency. Mostly for this reason, it is an inefficient and risky way of

demonstrating financial guarantee for ex -post obligations. For instance, in case of contingencies

such as sinking of the platform, the guarantee instrument is included in the physical losses.

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Real Estate Collateral Bond (RECBs)

This mechanism consists of placing a real estate property (of equal or higher value) as a

collateral guarantee for the completion of contractual obligations. Real Estate guarantees can be

secured for long periods. The market value must be payable to the regulatory agency under a

Deed of Trust and must be sufficient to cover all ex-post obligations under the contract.

In order to eliminate some of the risks involved in the acceptance of this instrument, a

contract is drawn establishing the regulatory agency as the only beneficiary of the property in

case of default or insolvency. In addition, the property must not be part of the area involved in

the project and must be free of liens or loans. During the entire life of the project, an independent

agent must monitor the market value of the property. If the property value falls bellow the value

required by the bond, the regulatory agency must be notified and a new form of guarantee must

be promptly provided. Real estate properties carry very low liquidity and create additional

regulatory costs. Besides, in case of default, the selling process is complex and may be long.

Often, the agency is forced to sell the property for a value significantly inferior, allowing

additional costs to tax payers. Direct costs caused by this instrument are very low, however some

other costs such as taxes, legal fees, depreciation, and market fluctuations, may incur.

The acquisition of a real state property as a form of investment is not a good way to

allocate capital, since there is no guarantee for the value of money. If the property already

belongs to the lessee, it would reduce the total capital allocated as a collateral guarantee, reducing

opportunity costs for the lessee. If pledged as a financial guarantee, the lessee is unable to use

the same piece of real estate as collateral for other ventures, including obtaining loans.

Treasury Bonds and Investment Grade Securities (T-Bonds and IGSs):

Investment Grade Securities are instruments that offer annual interests and may come in

several forms. They are generally bought with long maturing terms in order to avoid frequent

substitutions and keep higher earnings. The most common IGS instrument used as collateral to

demonstrate fmancial guarantee for ex-post obligations are bonds issued by various levels of

government (debt instruments with fixed terms). Government-issued notes are usually kept until

their maturity (term), but they can be negotiated in the market without penalties. When used in

this context, government bonds are usually negotiable and transferable, so some additional care

must be taken protecting the document. IGSs are as good as the institutions issuing them. IGS

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bonds pay interest, guaranteeing the value of the money allocated. In order to avoid the volatility

of the market, regulators tend to recommend US Treasury Notes. The regulatory agency has the

right to sell the securities if the company does no meet ex-post obligations. Funds acquired will

be used to complete all ex-post operations. After maturity, bonds are redeemed by the face value

plus accumulated interest. This instrument category offers good efficiency even for long terms

projects.

Leasing-Specific Collateral Accounts, Leasing-Specific Abandonment Accounts, or Periodic

payment Collateral Accounts (LSCCs, LSAAs, or PPCAs)

This category works similarly to PPCAs; however, some flexibility is added in the way

payments are made. There are several variations of this instrument. Payments must be

completed within a pre-determined period according to a formula provided by the regulatory

agency. The format adopted by the MMS requires a company to commit itself to fully fund the

LSAA within four years or, by the beginning of the year in which the agency projects that the

company will have cumulatively produced 80% of the originally recoverable reserves, whichever

is first.

The first payment is generally equal to or greater than 50% of the estimate of the

cumulative potential lease abandonment and clearance liabilities (ex -post costs). The company

will base the amount of the initial payment on the agency's analysis of rates of production from

other leases, cash flow for similar projects, characteristics of the producing reservoir( s ), plugging

and abandonment information available in the agency's databases, and/or other information

provided to the agency.

The objective of the MMS is to establish a time schedule for incremental payments that

will ensure that the deposited amount in the LSAA will increase at a faster rate than the rate at

which the originally recoverable hydrocarbons are being produced from the lease. In actual

projects, the agency may require the submission of a risk insurance policy in order to cover

residual liabilities21 in the event that a catastrophic failure or other contingencies may prevent the

completion of the remaining payments.

Table 6.8, on Chapter VI, is a demonstration of the time schedule for incremental

payments of a LSAA bond. It indicates the time schedule adopted and the amount of each

21 Some agencies require post closure fmancial assurance for a 30 years period after closure (GAO, 1994).

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incremental payment to fund the account over a four-year period. The following example

describes the situation on a hypothetical oil-producing field. A LSAA must be funded with

$17.25 million, which is the value of the bond. The amount of the initial payment is 50% of the

field's cumulative potential decommissioning costs, which is equal to $8,63 million. By the end

of year 4, even if the company were not able to produce 80% of the recoverable reserves

originally in place, the account would need to be funded with the full $17.25 million. Notice

that, yearly payments of $2.16 million during the 4-year period increased the fund from $8.63

million to $17.25 million by the end of year 4. Interests earned are transferred to the oil

company. Even complying with all LSAA bonding requirements, companies still have to pay

with out-of-packet funds to cover ex-post operations at the end of projects. Other examples are

illustrated in Chapter VI.

Instruments under this category discreetly eliminate opportunity costs from large upfront

disbursements. However, these benefits are only possible with the transference of some risk to

the agency. With periodic payments, there is no real guarantee that the total value of the bond

will be available if the lessee defaults before the account is fully funded. This risk is being

reduced by the requirement of the following mechanisms: (1) requirement of an insurance policy

in the value of the owned amount; (2) requiring a short period for funding the account (usually

four years); (3) establishing the agency as the only beneficiary of the account; and (4) making the

contract irrevocable. The attractiveness of these instruments also depends significantly from

fiscal incentives. The account management also generates some taxes and fees. In addition,

these measures demand additional monitoring and regulatory costs.

Letters of Credit (LOCs)

Letters of Credit are documents issued by financial institutions authorizing the holder to

receive a specific value. More specifically, a line of credit in the name of an oil company is

issued to guarantee that the amount required to complete all ex-post obligations will be available

in case of default. LOCs are negotiable instruments that specify the maximum amount of

available credit. The fmancial institution will deduct annual premiums, taxes, interests, and other

fees in order to maintain LOCs. LOCs can be negotiable or non-negotiable instruments (most

commonly non-negotiable) and are usually issued for one-year terms with evergreen clausei2•

22 Evergreen clauses allow automatic renewals or "rollovers".

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However, renewals depend upon the approval of the financial institution, which may decide not

to extend the instrument based on new developing factors that indicate increasing risk of default.

In this case, what happens is the equivalent to a situation of noncompliance, and the beneficiary,

the agency, may redeem the face value of the LOC. All three parts have great interest in avoiding

this situation.

Premiums and fees are often based on a credit evaluation of the candidate company.

Under ideal conditions, only soft collaterals are required. In order to reduce the risk of non

payment, regulators may require a letter of credit contract involving three parties (the issuing

institution, the oil company, and the regulatory agency). Letters of credit preferably should be

irrevocable and have the regulatory agency as the only beneficiary. The oil company will not be

able to use the established credit or the involved collateral to fund ex -post obligations.

LOCs, indeed, behave as nonnegotiable instruments. No institution would pay the face

value of an LOC to a party other than the specified beneficiary. Any contract changes must be

approved by all three parties (agency, principal and beneficiary).

Contract terms for a LOC will have the same provisions involved in the end-of-leasing

contract between the lessee and the agency. Some specific terms are included to govern over

circumstances that will pennit the redeeming of the instrument by the beneficiary, including

missed deadlines, negligence of specific operations, and unacceptable standards and levels of

quality.

Usually, premiums and fees for the maintenance of LOCs are very reasonable and

negotiable, but costs will depend on the credit evaluation of the principal (usually a percent of

the financial guarantee being required). Under most regimes, expenditures originated on the

establishment of an LOC may be deducted from corporate taxes. Once the LOC is established,

maintenance costs are low, but the principal is obligated to refund the LOC issuer all interest

related to funds withdrawn by the beneficiary. Small, newly formed, and independent lessees

may encounter some difficulty in obtaining a LOC, and probably would have to provide the

issuer with the deposit of the entire instrument face value as collateral.

LOCs will reflect the credibility of issuing institution. They are as good as the

institution issuing them. If the financial institution is currently in trouble, the instrument offers

great risk. If the financial institution becomes insolvent, the instrument is no longer a guarantee.

In order to reduce risks, the agency must carefully monitor issuing institutions, what may

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significantly increase regulatory costs. The agency may also require the establishment of a

combination of LOC with a standby collateral account.

Line of Credit Collateral Bonds (LCCB)

A LCCB is not a negotiable instrument but behaves like a LOC. This instrument is

essentially an agreement made between a financial agent, who lends the necessary funds, and the

lessee. The fmancial agent becomes responsible to fund all ex -post operations in case of default.

The maximum credit value must correspond to the costs of contractual ex -post obligations.

LCCBs must not depend of possible fluctuations in the financial health of the lessee. On the

contrary, the financial agent must disburse of the amount pledged without defiance. In case of

default, funds are withdrawn as needed by the agency, until a maximum amount contractually

approved.

Financial agents usually require collaterals for the establishment of LCCBs. Direct and

indirect costs may be significant. For regulators, high regulatory costs are also expected. A

Standby trust fund may also be required in combination with a LCCB.

Third-Party Bonds (TPBs)

TPBs are common in the mining sector and some oil agencies may accept them under

some circumstances. Requirements are significantly more severe and complex. Each agency has

its own complex list of requirements involving formulas and specific questionnaires for both

lessee and parent company.

Self Bonds (S-BONDS)

A self-bond is a form of waiver provided by the regulatory agency to companies that can

provide some specific financial requirements (unencumbered net assets and net worth tests).

There is a wide range of self-bond variations, also called financial tests. Some agencies are

considerably rigorous in granting these instruments and others are not so rigorous. Self-bonds

differ significantly from third-party guaranties and from other flexible collateral instruments such

as set-aside revenues, salvage, and real estate. In general terms, self-bonds are based on the

assessment of the assets and responsibilities of the lessee and its capacity of paying for and

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performing ex -post obligations. Flexible self-bonding mechanisms can offer significant risks to

regulators.

Third parties do not back self-Bonds. In addition, the lessee is not under the obligation of

providing collaterals or other guarantees. Usually, in order to benefit from this instrument, the

lessee has to observe certain criteria determined by the agency. Self-bond criteria vary

significantly; involving simple and complex formulas, net working capital and tangible net worth

calculations, credit rating, ex-post operation experience, etc. Ideally, only major, experienced

and historically competent companies should qualifY.

S-bonds may benefit companies that have been established in the oil business for a long

time, maintain a good financial health, sound environmental record, etc. S-bonds do not require

premiums or fees, nor cause opportunity costs, eliminating all direct costs. Indirect costs do

apply and reduce the company's capacity in obtaining loans and increase credit cost.

This instrument category is very criticized by different groups that tend to expect more

liquidity from bonding instruments. The mining sector has shown that large and historical

companies can also default, become insolvent and bankrupt. The risk for large companies

plunging into a crisis may be small, but catastrophic since most large companies are associated

with several large projects with the potential of generating large and catastrophic ex-post

environmental damage. In addition, if a lessee is a subsidiary from a large parent company, both

should be financially responsible for all ex-post obligations.

These past years have shown that a company's financial situation can be easily

manipulated, stockholders can be deceived, and gigantic companies can pretend to be extremely

lucrative on day, and go bankrupt next morning. Political manipulation of markets demonstrated

in the Enron incident involving allegations of excessive political influence and manipulation

among United States Representatives, involving even the current Bush administration, should be

an opportunity to consider a more secure form of guarantee for large companies and projects.

Future Revenue Commitments, Budget Set-Asides, Corporate Guarantees (FRCB, BSAB,

CGB)

These instruments are somewhat similar to self-bonds and, most of the times, it is

difficult to differentiate them apart. Companies using this category of instruments have to fulfill

armual criteria. Set-Asides, for instance, allow a company to use as guarantee the resources it

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intends to gain. This can become very complex and controversial. For instance, what is the risk

scenario involved in a marginal field being operated by a small company that uses one of these

instruments as a performance bond?

Direct impacts are nonexistent under this category. However, depending on the

instrument, indirect costs may become very undesirable. For instance, the set-aside instrument

will reduce drastically the capacity for acquiring loans and increase the cost of credit. This

category offers great flexibilities to the industry; however, it comes with a considerable cost to

the agency, including monitoring costs and high default risk.

Pool Bonds (P-BONDS)

A poll bond is a form of consortium of operators (usually small or newly formed

companies) designed to provide flexibility by spreading the risk of non-compliance and

minimizing bonding costs for associated parties. Associated companies become responsible for

making payments towards a common fund, which will be available in case of default of one of

the parties. Payments are usually based on a percent of the production, and are nomefundable

and nondeductible. Associated lessees have no control over the fund, which is managed by an

independent trustee. Some regulators argue that pool bonds only attract the interest of risky

parties. Indeed, pool bonds spread risk among associated companies, and only lessees under

extreme high-risk conditions would be interested in type of deal. In addition, monitoring and

regulatory costs are significantly high for regulators.

Insurance Policy Bonds (IPB)

An insurance policy is a two-party contract transferring existing ex-post liabilities on an

existing lease contract (up to the policy value) to an insurer. Insurance companies offer a wide

variety of environmental insurance products; however, in order to be accepted by most regulators,

a financial guarantee, policies must be irrevocable, free of liens and loans, have a pre-paid single

premium, and have the regulatory agency as the only beneficiary of the policy.

Annuities Policies (APs)

An annuity works like a series of payments (or a single large payment), made by an

insurance company (or another financial institution) in behalf of the principal, the Jessee, in

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exchange by an upfront premium paid by the principal. When the instrument is bought, the

insurer becomes contractually obligated to cover payments in favor of the principal, whenever

required. These payments, or single payment, are equivalent to continuous and/or ex-post

environmental obligations. Payment program must be defmed at the time the policy is signed.

In some special circumstances, irregular payment fluxes are permitted.

Since payments can be made periodically or at a single installment, the lessee may

benefit from interest earnings, guaranteeing, at least, the value of money. In addition, lessees

may also benefit from acquiring annuities at values significantly inferior to the required bond

amount. Longer periods allow greater benefits, greater interest earnings, significantly reducing

opportunity costs. Annuities do require the payment of premiums and some fees; however, this

instrument offers one of the lowest direct costs among all instruments considered.

The contract defining the payment schedule must coincide with environmental obligations

being covered by the policy. Annuities offer an adequate guarantee for long-term projects, and as

other insurance products, annuities may backfire on regulatory agencies. Since annuities behave

like insurance policies, in case of default insurers may provide legal reasons to exonerate

themselves from paying the bond. Collecting annuities may require long litigious battles. For

this reason, some agencies will only accept annuities upon the presentation of collaterals (i.e. a

standby trust), which, most of the times, eliminates all benefits provided by the policy. In order

to reduce risks, the agency must be irrevocably established as the only beneficiary of the policy.

Environmental Insurance Policies (EIPs) EIPs are contracts where the insurer promises to pay for all ex -post environmental

obligations in behalf of the lessee to the beneficiary, the agency. The face value of the policy

must be I 00% ex -post obligation costs. The policy must also guarantee that resources, up to the

face value, will be promptly available when necessary. Policies must be kept active for the

entire length of the project. EIPs must be irrevocable, except by default of premium payments.

Until recently, insurance products for ex -post environmental obligations in the oil and mining

sector were rare. The insurance sector now offers innovative and flexible products, which may

be adjusted to fulfill specific regulatory needs. Some products may be directed to cover

liabilities from personal damage or damage to third-party properties.

Premiums are set based on the cost of potential loss and the probability of default. The

insurer assumes the total liability. In order to provide optimum guarantee, agencies should

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require single pre-paid prenuums, and irrevocable contracts (single premium whole-life

policies). Unfortunately, in case of noncompliance, the insurer may, and they typically do,

question judicially the payment of the policy, delaying the availability of funds to the agency.

Finite Insurance Policies (FIPs)

F!Ps cover known ex -post environmental obligations and losses associated with the

discovery of new environmental obligations. This is a new and very interesting product offered

by AIG (1998). F!Ps have a total aggregated value and multi-annual terms for log-term

projects. Perhaps, the greatest innovation offered by F!Ps is the possibility of a personalized

policy, which attends to all lessees needs, regulators desires, and to specific ex-post

environmental demands of the sector.

F!Ps are structured to allow the sharing out of costs and profit between the insurer and

the lessee. Premiums are paid fully at the beginning of the policy and corresponds to the NPV

of the estimate balance to complete the full payment of all ex -post environmental obligations.

The premium will cover the required value and even a possible pre-established additional

amount for ex-post eventualities. Great part of the premium is allocated into an account that

will be rewarded with the same annual interests paid by US Treasury Notes (around 5.5%), and

paying the losses during the length of the project, if any. The insurer will manage the account as

it wishes. However, only revenues equivalent to interests paid by the US Treasury Notes will be

deposited at the "Notional Commutation Account" (NCA). If investments allow better earnings,

the balance will go to the insurer. If there are losses in the process, the insurer remains

responsible for paying agreed interests into the NCA. If the total expenditure is less than

previously estimated, the insurer must return the balance to the NCA to the lessee (Tables 4.2

and 4.3).

F!Ps reqmre significant upfront capital allocation, causing direct costs including

opportunity costs. However, the NCA is rewarded with interests and profits, and shared

between the insurer and the lessee (Figure 4.8). There are no annual premiums or fees.

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TABLE 4.2. COMMUTATION ACCOUNT BALANCE- FINITE INSUR.Ai-.CE Optimistic scenario

Year Comm. Account Investment Loss Comm. Account @) Beginning Income Pal:ment @)End Year

1 9,918,463 545,515 200,000 10,263,979 2 10,263,979 564,519 200,000 10,628,498 3 10,628,498 584,567 200,000 11,013,065 4 ll,013,065 605,719 200,000 11,418,784 5 11,418,784 628,033 200,000 ll,846,817 6 ll,846,817 651,575 2,500,000 9,998,392 7 9,998,392 549,912 2,500,000 8,048,303 8 8,048,303 442,657 500,000 7,990,960 9 7,990,960 439,503 500,000 7,930,463 10 7,930,463 436,175 500,000 7,866,638 II 7,866,638 432,665 500,000 7,799,303 12 7,799,303 428,962 500,000 7,728,265 13 7,728,265 425,055 500,000 7,653,320 14 7,653,320 420,933 500,000 7,574,252 15 7,574,252 416,584 500,000 7,490,836

Total 10,000,000 Under this optimistic scenario, the insurer would pay out $10 million in losses and the insured would receive a profit of $7,490,836 at the end of the term. 84.8% of the premium paid went originally to the notional commutation account, which will be used to pay losses. 15.4 % of premium payment is used to pay expenses, taxes, and risk assumption charges. Source: RADIGAN (1996)

TABLE 4.3. COMMUTATION ACCOUNT BALANCE- FINITE INSURANCE Pessimistic scenario

Year Comm. Account Investment Loss @ Beginning Income Payment

1 9,918,463 545,515 6,000,000 2 4,463,979 553,519 6,000,000 3 (1,290,502) 1,000,000 4 (2,290,502) 1,000,000 5 (3,290,502) 1,000,000 6 (4,290,502) 1,000,000 7 (5,290,502) 1,000,000 8 (6,290,502) 1,000,000 9 (7,290,502) 1,000,000 10 (8,290,502) 1,000,000 II (9,290,502) 1,000,000 12 (10,290,502) 1,000,000 13 (11,290,502) 1,000,000 14 (12,290,502) 1,000,000 15 (13,290,502) 1,000,000

Total 25,000,000

Comm. Account @End Year

10,063,979 10,217,498 (2,290,502) (3,290,502) ( 4,290,502) (5,290,502) (6,290,502) (7,290,502) (8,290,502) (9,290,502)

(10,290,502) (II ,290,502) (12,290,502) (13,290,502) (14,290,502)

Under this pessimistic scenario, the insurer would pay out $25 million in losses and the notional commutation account would be negative, but since the term sheet did not indicate any additional premiums, the insurer would not be obligated to pay this back. The insurer assumes this risk (underwriting and timing risks). Source: RADIGAN (1996)

127

FIPs have different applications. They could be used to protect ex-post processes and

even post-closure processes of waste facilities, mine closures, end-of-leasing operations in the

petroleum sector, including decommissioning of offshore facilities, decommissioning of nuclear

power plants, etc. This product offers a great incentive, which is the opportunity to anticipate

deduction from corporate taxes.

The allocation of up front capital used to demonstrate financial guarantee (anticipating

costs of ex-post operations as it occurs with collateral bonds, LSCAs, and other) cannot be

deducted from corporate taxes until expenditure actually occurs. Most of the times, when this

condition is fulfilled, there are no more revenues to be deducted from. Discount rates offered by

insurance companies may be better than after tax investment rate of the insured. Usually,

insurance companies that offer FIPs have great operational experience, and can provide

auxiliary expertise to ensured companies, reducing risks and allowing better ex -post

performances.

FIPs offer an efficient guarantee for ex-post liabilities including some possible

"overruns" on long-term projects. Policies carmot be used as collateral for other ventures or

loans. FIPs offer a single pre-paid premium, a policy that is irrevocable and free of liens,

collaterals, and, mainly, a policy that establishes the regulatory agency as the only beneficiary of

the policy.

The ensured transfers all liabilities to the insurer. For this reason, there is the need for

monitoring the insurer, creating some additional regulatory costs. Most regimes have a sector to

oversees insurance companies, avoiding monitoring costs to the agency.

Insurance-Guarantee Policies (IGPs)

This insurance product is being proposed to satisfy financial assurance requirements in

Brazil. IGPs, as other insurance policy products, transfer liabilities from the lessee to the

msurer. The face value of the policy may not surpass 1 00% of contractually defined ex -post

obligations. The policy is active throughout the length of the project and is only released after

the fulfillment of all ex-post obligations. Theoretically, when the ensured party defaults, the

beneficiary has the right to request the face value of the policy to fulfill ex -post obligations after

the refusal of the ensured to comply with an extra-judicial warning. After paying the policy, the

insurer has the right to pursue reimbursement from the ensured.

128

1\ EXCESS i

INSURANCE J

PRIMARY INSURANCE

I I i I

I I

RETENTIO-~ '----------------~

1 year

_-_.-

FINITE INSURANCE

EXCESS --rl INSURANCE _j I

FINITE INSURANCE

I I , I I I I

I I FRETENTIONS ~ ~____'" --------\j

Multiple Years

I Risk Transfer Layer ...

. 5 Risk .... Funding c Trasfer

" Layer LL.

i r-

Risk ~ Transfer i

r--'

I~ Funding

":---------____./)I ·--- ---------------------------------------------------------- ---------------------------------------------------------------"~)

Figure 4.8. Finite Insurance structure compared to traditional environmental insurance policies, and different methods of funding finite insurance.

Insurance companies have a criterion to define premium rates and the maximum policy

value. Depending of the ensured classification, collaterals and other guarantees may be

required. When required, guarantees will correspond to a minimum of 130% of the policy. In

many aspects, an IGP is similar to a surety bond. However, the basic principle of an insurance

policy is the transference of liability from the ensured to the insurer, and the principle of a surety

bond is the guarantee of credit (CORNWELL, 2001; UNICAMP/CEPETRO, 2001).

This is a relatively new product and further studies are required in other to identizy

impacts on the industry and on regulators. Insurance companies usually offer 8% of the

129

As it is the case of CCCPs, PLLPs have a specific application, but cannot be used alone

to demonstrate financial assurance. These instruments are highly recommended as auxiliary

instruments.

State Funds (S-Funds)

A State fund consists of a special account established to receive funds from all companies

involved in the exploration or production of hydrocarbon resources in a specific region.

Payments may be based on production, accumulated revenue, or in a percent of estimated ex -post

costs. Most commonly, this mechanism is used as a state-managed account, providing funds for

emergency actions (accidental environmental damages) in high-density exploration and

production areas where it may be difficult to identify the responsible party for damages that

require prompt mitigating response. Funds are nonrefundable. If the fund is withdrawn, the

company found responsible for the damage must promptly refund the account.

Several instruments may be used to provide guarantee for ex -post environmental

obligations. Unfortunately, all instruments have limitations, which can, in certain circumstances,

expose regulatory agencies to excessive financial liabilities. Even with the best of intentions,

some lessees may not fulfill or may only partially fulfill their ex-post obligations. In addition,

even well designed bonding systems eventually fail, leaving the financial liability to taxpayers.

An advantageous strategy would be establishing a safety net to cover eventual financial assurance

breaches or loopholes. Contingency funds fall into this category. They are auxiliary mechanisms

to go along with financial assurance systems. S-Funds may also be used for emergency actions,

including remediation of spills and other emergencies in offshore provinces. S-Funds have been

used in the United States with several levels of success.

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4.9. FINANCIAL ASSURAJ."'CE SYSTEMS

Several versions of financial assurance systems were identified and examined during this

study. What follows is a brief description and analyzes of four U.S. bonding regimes. The

reason for choosing them is that these regimes are the oldest bonding system in operation

identified and, for this reason, possess the longest uninterrupted experience. The systems are:

• Office of Surface Mining (OSM)- Coal Mining

• Bureau of Land Management (BLM) - Hardrock Mining

• Bureau of Land Management (BLM) - Onshore Petroleum

• Minerals Management Services (MMS)- Offshore Petroleum

4.10. THE FINANCIAL ASSURANCE SYSTEM IN THE US COAL MINLJIIG INDUSTRY

(US OFFICE OF SURFACE MINING RECLAMATION AND ENFORCEMENT)

Within the coal-mining sector, performance bonds used to guarantee closure operations

are know as reclamation bonds, closure bonds, and rehabilitation bonds. The following bonding

regime description was obtained through interviews with OSM personnel (OSM, 2000c;

STOKES, 2000; BRYAN, 2000). The OSM of the US Department of the Interior was created

with the objective of protecting the enviromnent during coal mining and guaranteeing that the

land is reclaimed when operations cease. The agency was created by former President Jimmy

Carter with the signature of the Surface Mining Control and Reclamation Act of 1977 (SMCRA).

The OSM has approximately 650 employees nationwide and works in partnership with

producing states. The primary responsibility for regulating surface coalmine reclamation belongs

to the states themselves. Twenty-four coal-producing states23 exercise this responsibility. For

the remaining states (Tennessee and Washington), federal lands and Indian Reservations the

OSM issues coal-mining permits, conducts the inspections, and manages enforcement

responsibilities.

The OSM's current annual budget is approximately US$ 273 million. With that sum, the

agency assists states surface mining programs and pays 100% of the costs for restoring

abandoned mine lands that were left unreclaimed before the present regulation. Financial

23 The following states have adopted their own coal regulatory system: Alabama, Alaska, Arkansas, Colorado, Illinois, Indiana, Iowa, Kansas, Kentncky, Louisiana, Maryland, Mississippi, Missouri, Montana, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, and Wyoming.

132

resources for reclaiming abandoned mines come from tonnage-based reclamation fees (royalties)

paid by active coal mines.

As a practical result of the current legislation, past abuses in coal mining operations

ceased. Coalmine lands are reclaimed as operations advance and mined lands are no longer

abandoned without proper reclamation. Current numbers show:

• Over 76,9 million m2 of pre-1977 dangerous abandoned mine waste piles have been

restored to productive use 76,9 million m2 (19,000 acres);

• Over 823,000 linear meters of dangerous cliff-like highwalls have been eliminated;

and

• Over 20,000 dangerous abandoned portals and hazardous vertical openings have been

sealed.

Since it began (1977), the Abandoned Mine Land Trust Fund collected over US$ 5 billion.

Since 1979, when states began receiving abandoned mine land reclamation grants, over $2 billion

has been distributed from the fund.

General description

Most mining regulatory regimes around the world now require mining closure procedures.

The ex -post process usually comprehends mine rehabilitation, site reclamation, and restoration

(establishment of vegetation). Activities comprehend underground and surface structures and

infrastructure, site reclamation, water management, re-vegetation (restoration), topographic

restoration (when possible), etc. Mining closure processes are divided into two distinctive

phases: (I) an active phase, and a (2) passive phase. The active phase comprehends the

reclamation of the site, and the passive phase, the monitoring and the waiting period for the

establishment of vegetation.

The Surface Mining Control and Reclamation Act of 1977 (SMCRA) states that, before a

company obtains a coal mining permit, it must furnish a financial assurance in the form of a

Reclamation Performance Bond24, to ensure that funds to reclaim the site will be available in case

24 Reclamation bonding is a long term connnitment and is a normal cost of doing business for today's coal mining industry

133

the company fails to complete its reclamation obligations m accordance with the approved

reclamation plan.

The major goal of Federal and State coal regulatory programs is to ensure that the

environment and citizens are protected during mining and that the mined land is reclaimed and

restored to beneficial use following mining.

Regulatory agencies have different requirements (Federal, State, and County). The

instruments used are similar; but there are different reclamation and closure requirements in each

State. The Federal government does not regulate the reclamation of hardrock mines. Each State

has its own requirements for hardrock and oil extraction (see BLM and MMS Bonding System

descriptions).

Permit

Before posting a bond and getting an operation permit, a mining company must have a

closure plan approved by the OSM. The closure process involves not only reclamation activities,

but it must also meet Revegetation Success Standards (RSS) that are either in the permit or in the

regulatory program.

Mining companies must provide bonding for 100% of what would be required to reclaim

the mine at the point of maximum disturbance25 during a given 5-year term of the permit.

Permits are renewed every 5 years. As mining progresses, bonds are adjusted to cover new

projected disturbances. The only way to obtain the required bond amount reduced is to apply for

full or partial bond release as reclamation progresses.

After all the ex -post requirements and environmental performance standards have been

met, the reclamation bond may be released. Nonetheless, even after all ex-post obligations are

satisfactorily met, the agency requires a 5 to 1 0-year waiting period (based upon average

precipitation) that represents the long-term liability period for the reestablishment of vegetation

(all standards have to be met including diversity, cover and production).

25 Such situations could be referred as the worst-case scenario, as suggested by COSTANZA (1992) and CORN'WELL (1994).

134

Forms of Bonds

The OSM acknowledges three major categories of reclamation bonds: Corporate surety

bonds; Collateral bonds (cash; certificates of deposit; first-lien interests in real estate; letters of

credit; federal, state, or municipal bonds; and investment-grade securities); and Self-bonds

(legally binding corporate promises without separate surety or collateral, available only to

companies which meet OSM financial tests). State regulatory programs will vary somewhat, but

in general, they will accept the above categories. Some States will not incorporate the self-bond

option.

All forms of bond must be made payable to, or pledged to, the regulatory authority (OSM

and/or the applicable State regulatory authority). The OSM may allow the company to post a

combination of acceptable bond forms. The total sum of the bonds furnished must equal to the

required bond amount.

Bond Amount

The amount of the bond is based on estimated third-party costs to complete the

reclamation plan in the event of forfeiture (including profit and overhead). The regulatory

authority sets the bond amount based on the operator's cost estimate for reclamation.

There are strict requirements for each form of bond. Bond providers or issuers (surety

companies and other financial institutions) are subject to the Jaws of their regulators: State

insurance commissioners, State banking examiners, and the Comptroller of the Currency.

Reclamation bonds cover all operations during the term of the permit. Before a permit is

issued, a bond must be posted to cover: (I) the entire permit area; (2) the initial area of! and to be

affected under a cumulative bond schedule; or (3) the initial area of land to be affected under an

incremental bond schedule. Under either cumulative or incremental bond schedules, the

company must post additional bond before affecting lands in succeeding increments or additional

lands in accordance with the approved cumulative schedule.

Self-bonds could be explained as OSM's acceptance of a company's assets, current and

forecasted financial health, and compliance record as the sufficient guarantee that the company

will perform all its ex-post environmental obligations. In order to obtain and maintain

qualification for self-bonds, companies must sustain a tangible net worth of at least $10 million,

135

maintain fixed assets in the U.S. of at least $20 million, and either meet certain financial ratios or

have an "A" or higher bond rating.

All collateral posted as bond must be owned solely by the applying company, free of all

liens, and valued at current market value not face value. The regulatory authority reduces the

market value of collateral by a margin sufficient to cover the regulatory authority's cost to

liquidate the collateral in the event funds are needed for reclamation. Certificates of deposit are

negotiable collateral instruments and need to be secured from loss and theft.

There are bond forms that will generate interest earning. As interest is earned, it may be

deposited into a separate account, or paid to the mining company by check periodically.

Essentially, interest is available to the mining company as it is earned.

Surety bonds and letters of credit require payment of annual premiums or fees. Annual

premiums are based on a percentage of the sum of the bond (or the amount of the letter of credit).

Premiums are not based on the risk of a claim being filed. When a surety company6 writes a

surety bond it guarantees that the mining company will reclaim the property. In case of default,

the surety company will pay the bond sum to the regulatory authority so it can perform the

reclamation. If a surety company is qualified, it may perform the reclamation in lieu of paying

the bond amount. However, the surety is held to the same level of compliance including the

long-term liability period. Corporate surety and letters of credit used to bond reclamation

operations in the coal mining industry must be noncancelable and irrevocable, even for the failure

to pay premiums and/or in the event of bankruptcy of the mining operator.

Surety companies charge according to the financial standing of the mining company (net

worth level), credit rating, and experience in the mining industry, etc. There is no Government

control over premium rates. The Surety Association of America (SAA) recommends premium

rates and every surety company has its own financial criteria to judge mining company

customers. Generally, the more net worth a mining company has, the smaller the premium will

be.

Mining companies that have used certificates of deposit as bonding collateral over the

ye ·:shave seen the interest rate drop from double-digit numbers in the 1970's to the current 5.0.

T principal amount of a certificate of deposit provides the reclamation guarantee (bond) and

the mterest is retained by the mining company.

26 A Surety company must be licensed in the State where the operation is located.

136

In some instances, fraudulent individuals posing as representatives of legitimate surety

companies have issued surety bonds. In order to avoid fraud, the operator may check the Surety

Association of America's (SAA) Obligee's Guide27 and the US Department of Treasury's

Circular 57028• Each form of bond has its own set of legal documents required by the regulatory

authority. Providers of the bonds (surety companies and banks) are subject to the laws of the

fmancial industry's regulators: State Insurance Commissioners, State Banking Examiners, and

Comptroller of the Currency.

Besides surety, collateral, and self-bond instruments, some States have OSM -approved

alternative bonding systems in the form of Bond Pools where mining companies pay a regular

fee based on tons of coal produced and/or acres permitted. The funds accumulate and are used to

reclaim any site where a member of the consortium fails to reclaim (bond forfeiture). Bond pool

systems are a combination of the conventional bonds (which guarantee the most costly part of

reclamation), and bond pool funds (which cover only the final stages of reclamation).

The Surface Mining Control and Reclamation Act of 1977 (SMCRA) also provides a

variety of financial instruments for a variety of area and staged systems for posting bonds.

Mining companies may post bonds to cover the entire permit area for the term of permit up front,

or post bond to cover the initial increment of land to be affected during the term of permit, or post

bond to cover a discreet area of land within the permit area (incremental bonding). The OSM

must pre-approve an incremental bonding scheme. Prior to affecting subsequent increments of

disturbance, additional bond must be posted by the mining company.

Up until 2000, approximately 75% of the bonds covering coal-mining operations were

corporate surety bonds. Small operations with bond amounts in the tens of thousands of dollars

tend to use certificates of deposit and other assets. Some individual bond amounts in excess of

US$ I 00 million are typically in the form of corporate surety bonds, letters of credit or self

bonds. Presently, there are approximately US$ 5 billion coal reclamation bonds in place in the

United States. Each State has its own database of bonding information. These tend to be updated

to show the current amounts but rarely keep historical records.

One of the major public concerns when the bonding concept is first introduced involves

the maintenance of bond and its provider's integrity during long periods (e.g. 30-year projects).

27 Surety Association of America's Bond Authenticity Program Obligee's Guide: http://www.surety.org/obliguid.htm 28 U.S. Department of the Treasury"s Approved Sureties Listing Treasury Circular 570: http://www.fins.treas.gov/c570/index.html

137

The Federal Government relies on the insurance/surety industry regulators (State Insurance

Departments) to regulate the financial requirements so that surety companies are solvent,

financially secure, for the duration of the bond. If an Insurance Department finds that a company

no longer meets financial tests, the company may be closed/liquidated. In addition, only sureties

that are listed in the U.S. Treasury as being financially qualified can issue surety bonds on

Federal properties. The Treasury evaluates all listed sureties armually and armounces to the

public if a surety company no longer qualifies to be listed. Mining companies must replace

bonds written by surety companies that are liquidated or taken off this list.

One of the worst foes of the coal mining industry is the formation Acid Mine Drainage

(AMD) (STOKES, 2000). The necessary attention to this important issue is not yet on the

official environmental agenda in Brazil, but it does not diminish the severity of such condition.

Once generated, AMD triggers more AMD and it may continue for centuries. Mitigation

operations may cost millions. The US and Canadian Governments and companies have directed

significant resources on innovative technologies and treatment techniques. Canada has

established a program named Mine Environment Neutral Drainage (MEND), in which a number

of stakeholders gathered together to develop technologies to control acidity drainage from mines,

allowing significant environmental and economic benefits (CANADA, 1996).

What would be the OSM response upon the anticipation of AMD for a specific project?

Would surety companies risk the possibility of assuming perpetual treatment for AMD? The

OSM will not issue a permit for a coal mine site where AMD is anticipated. If unanticipated

AMD occurs, the mining company must set up a trust fund, obtain insurance, or find a surety

willing to issue a surety bond for long-term coverage. The OSM has a specific policy statement

regarding AMD.

Understandably, cash is rarely given to the OSM to hold as financial assurance. Cash is

not an efficient way to finance long-term operations with high reclamation costs. One or more

surety bonds would likely cover a long-term commitment, a trust fund where money is deposited

armually in escrow, letters of credit, or perhaps some kind of environmental insurance. In

situations where cash is used, it would either be placed in an earmarked State/Federal treasury

account assigned to the applicable government agency or it could be placed in a bank in a

federally insured account under an Escrow Agreement between the mining company, the bank,

and the agency. Depending on where it is located, it would either be managed by the State's

138

fiscal staff if the money is in the State treasury (no interest would be earned), or the escrow agent

at the bank would manage it. The escrow agreement would specify that the State or Federal

agency have full control over the account until it is released after reclamation.

Sometimes it is difficult for people having their first glance at bonding systems to

understand that the resources set aside as performance bonds cannot be used to cover reclamation

costs when reclamation operations begin. A mining company cannot use the deposited cash to

fund the reclamation. The company has to pay for reclamation out of operating costs. After

successful reclamation and release of the bond, the money is returned to the mining company.

Bonds such as certificates of deposit, letters of credit, investment grade securities, and

real estate collateral can all be held for long periods. Certificates of deposit are set up to be self

renewing so that when they mature, they roll over for the next term( s ). Letters of credit are

typically issued with a one-year term but may contain an evergreen clause that allows the Jetter of

credit to roll over into the next term unless the bank gives the agency prior 90-days notice. If the

bank does not roll it over, the mining company must replace it with something else before it

expires, or stop mining and start reclaiming.

Real Estate could also be held for the long term but the mining company would have to

own the property in fee, free and clear of any liens. The mining company would have to provide

the agency with annual market value appraisals and updated title certificates to assure the

property is holding its value. The market value of pledged real estate (under a Deed of Trust)

must always be enough to cover the reclamation amount and liquidation costs if there were a

forfeiture of the bond.

Investment-grade securities such as U.S. Treasury Bills/Notes would be purchased with a

long maturity period to avoid the need for frequent substitution in order to keep earning the

interest.

Self-bonds are like the Financial Test arrangements under the EPA regulations. If a

mining company can meet certain net worth, fixed asset level, certain financial ratios (like assets

to liabilities), it may apply with the agency to self-guarantee its reclamation without a separate

commercial surety. Self-bonding is discretionary with the regulatory agency. Accordingly, a

company that meets all financial tests may be denied if it does not have a good compliance

record, or if it has a threatening pending lawsuit, for instance. Self-bonding requires the signing

139

of a contract known as an Indemnity Agreement, which is a promise to either perform the

reclamation or pay the amount to the regulatory authority.

The OSM offers several options for companies allowing flexibility, meeting all applicant

companies needs. According to the OSM, flexibility does not imply that anyone can get into the

coal mining business: "if a company cannot provide the expected guarantee, it will not be

welcome into the business". It is one way of eliminating environmental risk. Usually large and

financially healthy companies will end-up paying smaller bond amounts, since they are able to

meet financial tests required by self-bonds, but such companies have strong financial motives not

to forfeit their bond.

Analysis of the OSM bonding system

The OSM is the branch of the U.S. Department of Interior that regulates coal exploration

and production, and oversees the environmental protection during these activities, ensuring that

affected areas are rehabilitated after closure according to standards adopted in 1977, when the

agency was created.

The OSM bonding system is clearly aimed at safeguarding the agency against costs

related to the proliferation of abandoned areas (literary; with undefined ownership). A great

portion of these areas presents AMD problems requiring onerous and costly rehabilitation

operations, or perpetual treatment (indefinite control of produced acidity).

In addition to AMD problems, the agency fights a permanent battle with a excessive

number of litigious actions against the agency in which affected communities blame the OSM for

problems inherited by insolvent and/or irresponsible operators.

The OSM bonding system does not require financial bonds, only a performance bond in

the value of I 00% of rehabilitation costs plus indirect costs such as third-party profit and

overhead costs.

Among the four systems emphasized in this study, at the Federal level, OSM's offers the

widest level of instrument flexibility to participating companies, offering a generous portfolio of

instruments, allowing a large spectrum of participants, from independent operators (small scale)

to large corporations. Notwithstanding offering considerable flexibility, the level of success of

the OSM bonding system is commendable. The main reason for this success is the methodology

used to define the bond amount, which corresponds to the real costs of mine reclamation, offering

140

an adequate incentive for compliance. It has been observed throughout the preparation of the

present work that, most of the times, the value of the bond is more important than the type of

bonding instrument used.

Bonds are required as prerequisites for licensing and will only be released by the agency

upon the fulfillment of all ex -post obligations in accordance with the approved reclamation plan,

and after the observance of a waiting period in which the agency determines if the risk of residual

liabilities is acceptable and if the vegetation has been successfully reestablished.

One of the advantageous characteristics of the sector is that reclamation operations can be

performed concomitantly with mining activities (phased reclamation). Consequently, operators

can plan for phased-production, reducing the values of bonds and the period capital is allocated.

The accommodating portfolio of financial instruments acceptable as bonds by the OSM

includes: corporate surety bonds, escrow accounts, cash, Certificates of Deposit, Letters of

Credit, Treasury bonds, real estate, collateral of different assets, pool bonds, self bonds, among

others. Though the efficiency of the OSM bonding system is evident, the pile of lawsuits remains

bulky. A preliminary analysis indicates the following causes for the current scenario:

• Coal production is an activity accessible to small and independent operators, attracting

all sorts of participants, including high-risk ones.

• Producing areas are usually easily accessible, allowing the uncomplicated extraction

and transportation. However, these areas are in great part within inhabited areas,

exposing communities to risks and allowing easy public scrutiny.

• Coal is commonly associated with other mineral bodies with high tendency to produce

AMD.

• The US economy depends significantly on energy produced with coal. Consequently,

there is a noticeable political pressure to keep the attractiveness and competitiveness

of this sector, especially during times of high energy prices and international

instability.

• The OSM asserts that if, during the exploration and planning phase, the possibility of

AMD formation is identified, the project license is rejected. However, OSM criteria

seem considerably subjective and AMD problems are still common. Indeed, this is

one of the main problems related to lawsuits, in which the agency is blamed by the

public of negligence in allowing the licensing of high-risk projects.

141

• Another factor may be the excessive flexibility offered to small and independent

operators. If a mechanism to reduce the participation of high-risk operators were in

use, probably future lawsuits would be significantly reduced.

4.11. BONDING SYSTEM FOR THE US OFFSHORE OIL AND GAS

DECOMMISSIONING PROGRAM (US MINERALS MANAGEMENT SERVICES)

This item summarizes, describes and explains the MMS bonding system applied in the

U.S. OCS oil and gas, and sulphur leases (MMS, 2000; MIRABELLA, 2000; MARTIN, 2000,

WILLIAMS, 2000). Figure 4.9 shows the schematics of the MMS bonding system.

The MMS is a bureau of the U.S. Department of the Interior that manages the country's

natural gas, oil, and mineral resources of the OCS, and collects, accounts for, and disburses about

US$ 6 billion in revenues each year from offshore mineral leases and from onshore mineral

leases on Federal and Indian Lands (MMS, 1999). The MMS regulates the offshore oil sector by

overseeing drilling and production matters, pipeline operations, emergency shutdown systems,

inspection and testing of production and drilling equipment, decommissioning platforms, and

investigating oil pollution (OCS Lands Act).

Throughout the regulatory-making process, the MMS accepted the participation of the

industry and other stakeholders. Contributions that did not jeopardize public's best interest were

accepted by the MMS. In addition, worthy of mentioning is that, the MMS effort to make rules

accurate and comprehensible by providing online easy-to-read revisions that maintain technical

accuracy, and do not alter the substance of the law. The result is an efficient regulation that

provides adequate flexibility for companies to meet bond requirements and ensures that

companies adequately fund their ex-post environmental obligations.

Among the main objectives of the MMS are:

• Ensuring that companies are financially capable of completing all ex -post obligations,

safeguarding government and taxpayers by achieving a reasonable degree of protection

from default by a company at a minimum increase in regulatory costs including, costs

for lease, permit, or pipeline operations, and eventually, final cost to the public;

• Protecting the environment from potential harm resulting from a company's failure to

carryout proper ex -post environmental obligations in a timely fashion, including: well

abandonment and site clearance operations;

142

MMS Bond Flowchart

b)" Submitting ···· Posting Company's Agency's

;-~,r~t=o=t=b=e~A=··=g=e~nc=y~·;-----B_o_n_d_s ____ -t ____ A __ ct_i_o_n_s ____ t-___ A_c_t_io_n_s ____ 1

(.-"~ 1f Lease I

i ...•. . Application I ...... +

· ...

.

f Operation I 1 Activity Plan l Post a 50,000

BOND

Must manta in bond until lease ends .----+-----1 and company meets all obligations, or

until a higher bond is required

I Exploration

I Plan

Post a 200,000 I BOND__jH-----,

D&P Application

I I i D&P Plan

~~--~

Must manta in bond until lease ends f<Ott-----land company meets all obligations, or


Must maintain bond until lease ends and company meets all obligations, or


L---~---''-----~-~

(

Operation ceasses \ & all end-of-lease

1t---,

obligations are met /

JJ Bond is I I

II released and

.I any collateral I is returned to

I/ the company .

Figure 4.9. MMS Bonding System Schematics.

143

• Requiring bond coverage for holders of Geological and Geophysical (G&G) permits

(deep stratigraphic test well drilling) and authorizing a demand for supplemental bonds

for holders of G&G permits or pipeline right-of-ways; and

• Selecting a method for attaining such goals with fairness to all stakeholders

guaranteeing that all ex-post operations are completed in a satisfactory manner.

In the present MMS regulation, all co-lessees and operating rights owners are liable for

compliance with all terms and conditions of their OCS leases. When large producing companies

transfer OCS leases to smaller companies (some marginally financed), the risk of default and

non-satisfactory completion of ex-post obligations usually increases. To avoid such risk, all

parties involved in the negotiation (the assignor of the OCS lease and the new lessee) will be held

responsible for the compliance of all ex -post obligations related to the facilities the original

assignor installed.

General Bonds

The following falls under the main financial bond category, but are treated by the MMS

as general bond requirements. General bond requirements are the same for all applicants:

• Lease Bond: A US$ 50,000 single lease or US$ 300,000 areawide bond along

with the submittal of an operational activity plan. A lessee does not need to provide

this bond if an applicable lease or areawide bond is in place in accordance with one of

the following, higher requirements.

• Exploration Bond: A US$ 200,000 lease or US$ 1,000,000 areawide bond along

with the submittal of a proposed Exploration Plan (EP). A lessee does not need to

provide this bond if an applicable lease or areawide bond is in place in accordance

with one of the following, higher requirements.

• Development and Production Bond: A US$ 500,000 lease or US$ 3,000,000

areawide bond along with a proposed Development and Production Plan (DPP), or a

Development Operation Coordination Document (DOCD).

144

Supplemental Bonds

Evidently, ex-post costs will be higher than the US$ 500,000 financial bond amount

posted by the company. For this reason, the MMS may require additional security (a

supplemental bond or bonds) whenever the cost to meet all potential present and future lease

obligations surpass the amount of the general bond (US$ 500,000), except when the company, or

one of the current lessees, demonstrate to the satisfaction of the MMS financial capability to meet

the obligations.

Some of this supplemental bond will not fall precisely under the category of performance

bonds, for corresponding to an insufficient amount to guarantee the performance of all ex -post

obligations. However, this waiver granted by the MMS to companies that are able to

demonstrate financial capability, can be understood as a form of Self-bond. Companies required

to post a supplemental bond correspondent to 0% to I 00% of estimate ex -post operation costs

may be understood as a partial self-bond "supplemented" by the amount it was not able to

demonstrate being capable of paying if ex-post operations were to be performed at that moment.

In order to provide a more flexible and, at same time, efficient regulatory framework, the

MMS has established rules for the acceptance of Lease-Specific Abandonment Accounts (LSAA)

and third-party guarantees. In recent years, the MMS has set a higher and more realistic level of

bond coverage to the holder of a Geological and Geophysical (G&G) exploration permit to drill

deep stratigraphic test wells and also authorizes a demand for a supplemental bond from the

holder of a G&G permit or pipeline right-of-way. All situations are analyzed on a case-by-case

basis by the MMS.

If a company decides to use third-party guarantees, the guarantor will not be required to

qualify as a surety with the Department of the Treasury (Treasury) but it must agree to fully

perform all lease obligations without the dollar limitation permitted to sureties, as stated by the

MMSrule.

When a company is able to satisfactorily furnish evidence of its financial strength and that

all ex-post obligations will be met, the MMS will not require additional bonds. If the financial

strength of the company is considered not satisfactory to guarantee completion of all ex -post

obligations, then the MMS will require the posting of additional bonds to cover all potential

liabilities. All projects are susceptible to reviews. The supplemental bond amount may be

increased if the company takes on new activities. Likewise, it may be decreased if the company

145

completes any part of its abandonment and/or decommissioning plan that reduces its potential ex

post liability. There is a great incentive for the research of innovative technology in this area. If

a company can provide evidence, for instance, that the cost for removal of a platform installation

is much less than MMS previous stipulation, the requested supplemental bond amount may be

reduced. Note that the general bond amount (US$ 500,000) must be maintained until the lease

ends and all ex-post obligations have been successfully met, regardless of supplemental bond

ISSUeS.

The MMS will consider several parameters in order to estimate the total cost of ex -post

obligations, including:

• Financial (e.g. financial strength and credit rating);

• Cost estimates (e.g. well plugging and abandonment, and platform removal and disposal);

• Compliance parameters (e.g. decommissioning compliance record);

• No abandonment/decommissioning reasons: possibility that the company may get behind

in paying its due royalties.

Supplemental Bond Procedures

According to the MMS boding rule, a company will be required to provide additional

securities, supplemental bonds, when the estimate expenditure to achieve all potential present and

future lease obligations surpasses the general bond amount.

If one of the current lessees can demonstrate financial capability to meet all financial

obligations, including: rents, royalties, plugging and abandonment costs, and other necessary

operations to ensure performance of regulatory requirements; the supplemental bond will not be

required (waiver or self-bonding mechanism).

Assessment of Financial Strength

What follows is a summary of MMS procedures (applied to all OCS Regions) used in

assessing the financial strength of OCS lessees in other to implement supplemental bond

requirements.

Additional security will be for an amount not more than the full amount of ex -post costs

in cases when none of the lessees can demonstrate the fmancial capability and strength to carry

out present and future obligations.

146

Reviews

Reviews of Cumulative Potential Lease Abandonment Liabilities (CPLAL) are performed

when requested or when necessary (at any time). The MMS will review all lessee's general and

supplemental bonds, cumulative liabilities, and financial strength.

a. Subsequent reviews may be conducted when a company requests approval for:

• Assignment of the lease record title interest (lessee of record), or a portion of the

record title interest in a lease;

• Significant revision to an approved EP;

• DPP or a significant revision to an approved DPP;

• DOCD or a significant revision to an approved DOCD;

• Application for a pipeline Right-Of-Way (ROW) or modification to an existing

pipeline ROW;

• Assignment of record title interest of an existing or approved pipeline ROW permit

with platform amenities; and

• Significant revision to an approved pipeline installation plan for a pipeline having

platform amenities.

b. At MMS 's discretion, it may conduct reviews:

• Periodically;

• When it becomes aware of information that indicates a change in the financial strength

of the company or potential cumulative liability;

• When it issues Notices of Incidents of Noncompliance (NIN) for incidents related to

safety, environmental, non-payment of royalty, or other violations of MMS

regulations; and/or

• A lessee takes an action that causes the MMS to initiate a rev1ew and then the

company withdraws the action. At MMS' s discretion, it may carry the review of the

need for additional bonds to completion.

147

Evidence of Financial Strength and Reliability

If a company meets all the following conditions, the MMS will not require supplemental

bonds, unless it determines that the financial or operational history of the company justifies that a

bond is needed to ensure that the company will meet all ex-post obligations:

a. If the estimated cumulative potential ex-post liability is less than or equal to 25% of the

most recently available and independently audited calculation of the company's net worth, the

MMS will not require a supplemental bond if the company meets the additional criteria bellow (b

or c) and shows adequate reliability as evidenced by the following:

• Experience: number of years of successful operations and production of oil and gas

(or sulphur) in the OCS or in the onshore oil and gas industry;

• Financial: credit ratings, trade references, and verified published sources;

• Moral/Compliance: record of compliance with the current and previous governing

laws, regulations, and lease terms; and

• Other: items that indicate fmancial strength or reliability.

b. If a company produces fluid hydrocarbons in excess of an average of 20,000-barrel oil

equivalents (BOE29) per day from its OCS leases, based on MMS's calculation of company's

production for the most recent 12 months for which data and information are available.

c. If a company can demonstrate financial strength to carry out present and future

financial obligations. The company may exhibit financial capacity by providing audited financial

statements, including an independent auditor's report, balance sheet, and profit and loss sheet.

This audit must demonstrate that the lessee falls within one of the criteria identified below:

• Stockholders equity or net worth has a minimum value of US$ 50 million but does not

exceed US$ 100 million, the current ratio (current assets/current liabilities) is equal to or

greater than 1.0, and the debt to equity ratio (total liabilities/net worth) is less than or

equal to 2.5.

• Stockholders equity or net worth has a minimum value of US$ 100 million but does

not exceed US$ 150 million, the current ratio (current assets/current liabilities) is equal

29 BOE for natural gas: 5.62 thousand cubic feet of natural gas= 1 barrel of oil equivalent (BOE), as measured fully saturated at 14.73 psi and 15.6° Celsius (30 CFR 250.1203-b).

148

to or greater than 0.75, and the debt to equity ratio (total liabilities/net worth) is less

than or equal to 3.0.

• Stockholders equity or net worth has a minimum value of US$ 150 million, the

current ratio (current assets/current liabilities) is greater than 0.50, and the debt to equity

ratio (total liabilities/net worth) is less than or equal to 3.0.

d. The determination of financial strength is valid for one year, but it can be extended for

one year at a time if:

• An independent accountant submits verification of the company's current financial

capacity at least 60 days prior to the expiration of the current determination; and

• The company continues to meet the previous criteria.

Determination of the Cumulative Ex-Post Liabilities

The required supplemental bond will be equal to the cost of meeting all potential present

and future lease obligations including rents, royalties, and amount of plugging and abandonment

costs necessary to ensure performance of regulatory requirements, as mentioned before.

a. The MMS will estimate the amount of cumulative abandomnent liability including the

lessee's obligations to plug and abandon wells, remove platforms and other facilities, and restore

the lease to its original condition by clearing the obstructions from wells, platform sites, and

ROWs. The estimate is based on the assumption that all facilities will be removed and

abandoned onshore (total decommissioning).

b. Estimates are based on available historical costs (MMS database). The company may

provide additional information in order to assist estimate ex-post costs. When providing

additional data, the company should explain the basis for the data. The MMS will estimate costs

as follows:

• Plugging and abandoning a borehole will cost US$ 100,00030 per borehole for all

water depths.

• Costs for dismantling and abandoning a platform will vary with water depth

according to Table 4.4.

• Costs for clearing a lease will vary with water depth according to Table 4.4.

30 Estimate provided by both the MMS and Byrd and Twatchem (1999)

149

TABLE 4.4. MMS ESTIMATED EX-POST COSTS ACCORDING TO WATER DEPTH

Water depth of 46 meters or less

US$ 400,000

Water depths of 46 meters or less

$300,000

Estimated decommissioning Water depth between 46 Water depth between 70 and Water depth of90 meters

and 70 meters 90 meters or more

US$ 600,000 US$ 1,250,000

Estimated cost of site clearance

Water depths between 46 and 7 6 meters

$400,000

US$ 2,000,000 +

Water depths of76 meters or more

$500,000 +

Since developments in the continental shelf of many petroleum provinces have reached the 2,000 meters mark, the concept of deep waters has been somewhat altered and the terminology ultra-deep waters has been frequently used. Source of data: MMS (2000d)

c. The MMS will use the following procedure to estimate the need for and amount of

supplemental bonds:

• IdentifY all leases being held by the company.

• Apply lease specific bonds (i.e., lease specific general bonds, lease specific

supplemental bonds, and lease specific guarantees) to identified leases.

• Exclude from the company's lease abandonment and clearance liability calculation,

for the purpose of supplemental bond determination, up to the full amount of the

clearance liability for any leases for which the MMS has determined that one or more

co-lessees have such financial strength that it is not necessary to require submission of

a supplemental bond. The MMS will exclude less than the full amount in cases where

it is determined that additional security is needed as a result of previous financial or

operational record.

• Deduct a reserve account for the Royalty Management Program (RMP) from the

general bonds on file. The MMS will credit this account $50,000 per lease or

$300,000 per area-wide bond on file.

• Apply the remaining general area-wide bonds, or blanket bonds, to leases m

chronological order beginning with the lowest lease numbers on file.

• After calculating the remaining potential liability, the MMS will evaluate the

financial strength and reliability of the company and the need for supplemental bonds

and the amounts will be determined.

• Request lease-specific supplemental bonds from the company.

150

d. The company may provide detailed information on existing leasehold facilities in order

to assist the agency's evaluation. The company may also provide evidence to support an

adjustment in MMS's estimate of company's cumulative potential abandonment and clearance

costs. That evidence may include:

• The itemized data and information by lease used as a basis for company's estimate

of the cumulative potential abandonment and clearance costs represented by wells

and facilities on company's leases.

• The itemized data and information by lease on which a third-party bases its estimate

of company's cumulative potential lease abandonment and clearance costs.

e. When conducting a subsequent review of the need for a supplemental bond, the MMS

analysis will consider the number of wells drilled or plugged and abandoned in the time that has

elapsed since the last review of company's cumulative potential liabilities, the number of platform

installations or removals since the last review, changes in the amount and value of hydrocarbons

being produced, the projected rates of oil and gas production, inflation, and other changes in the

market conditions. The objective of the MMS review and analysis is to ensure that supplemental

bond coverage or alternate form of security provided is adequate to cover potential lease

abandomnent and clearance liabilities.

Compliance with Requirements to Provide a Supplemental Bond

A company may submit and maintain supplemental bonds in the following ways:

a. Submitting LSAA supplemental bonds, U.S. Treasury Securities, or an alternate form

of supplemental security approved by the MMS (MMS, 2000). If the value of the company's

security falls below the level of the supplemental bond required, or if the U. S. Treasury no

longer certifies the issuer, the company must notifY the MMS within 15 days.

b. Submitting, with MMS's prior approval, a LSAA funding plan according to 30 CFR

256.56. The plan must include the following:

• An initial payment into the LSAA that is generally equal to or greater than 50% of

MMS's estimate of the cumulative potential lease abandomnent and clearance liabilities.

151

• A prescribed time schedule for making specified incremental payments (e.g., monthly

payments) in amounts that will ensure that the amount in the LSAA will increase at a

faster rate than the rate at which the originally recoverable reserves are being produced.

• Commitment by the financial institution in which the Jessee established the LSAA to

notif'y the agency of the date and amount of the initial deposit and of each subsequent

incremental payment.

• Submitting a risk insurance policy to the agency covering residual liabilities in the

event of any catastrophic failure that prevented the completion of remaining payments.

c. The company must immediately submit, and maintain, a supplemental bond in an

amount equal to the remaining portion of MMS's estimate of the amount of company's

cumulative potential lease ex-post liabilities in the event the company fails to:

• Make the initial payment into the LSAA; or

• Timely deposit into the LSAA the amount agreed.

LSAA Steps (example)

• Total Supplemental Bond Payment= US$ 5,000,000.

• Initial payment = 50% of required bond. Since 50% is greater than the percentage

of the recoverable hydrocarbons originally in place that MMS projects will be

produced by the end of Year 1.

• By the end of year 3, the company will have produced 60% of the original

recoverable reserves. The fund will need to have not Jess than 60% of the total

supplemental bond (US$ 3,000,000 = 60% x US$ 5,000,000) by the start of year 3.

• By the end of year 4, the company will have produced over 80% of the recoverable

reserves originally in place. The LSAA will need to have the full US$ 5,000,000 by

the end of year 4. Quarterly payments of US$ 156,250 during the 4-year period will

increase the fund to US$ 5,000,000 by the end of year 4.

Using Third-Party Guarantees Instead of Supplemental Bonds

The company may submit a third party guarantee in lieu of a supplemental bond. The

guarantee must be provided by a third party (guarantor) who will guarantee compliance with all

152

lease obligations. There are severe regulations involving the acceptance of third-party guarantees.

The Agency will accept third-party guarantees if the guarantor and the indemnity agreement are

considered satisfactory.

Termination of Bond, Guarantee, or Determination that a Supplemental Bond is Not

Necessary

The Agency has the right to deny a company's request for finding that submission and

maintenance of a supplemental bond is not necessary, the agency has knowledge that recent or

anticipated future events may adversely affect the Iessee's/lessees' ability to comply with current

and/or future lease obligations. The MMS may also require supplemental bonds on any leases,

regardless of any prior determination, if it is determined that the operator has not fully and

consistently complied with regulations.

a. When any of the following occur, the company needs to immediately take necessary

action to meet these requirements. If the company does not, the MMS may issue a civil penalty,

stop operations on the lease, or take any other action authorized by the Outer Continental Shelf

Lands Act (OCSLA) or the implementing regulations.

• Supplemental bonds are required when the MMS had previously determined that

company's financial strength was sufficient that the MMS did not require a bond. In

such cases, the MMS will give the company a minimum of 20 days notice before

requiring a supplemental bond.

• The third party guarantor ends the period of the guarantee.

• The bonding company ends the period of bond protection.

• The value of company's security falls below the level of the required bond.

• The U. S. Treasury no longer certifies that the issuing company.

b. If the company chooses to provide a LSAA instead of providing a bond, the MMS may

allow the company with 70 additional days to prepare and allow the MMS to review a plan for

incremental payments and to add funds to the account, according to the plan.

153

Analysis of the MMS bonding system

The MMS is a Branch of the U.S. Department of Interior and regulates exploration,

development, and production of oil and gas in the U.S. Outer Continental Shelf (where the costal

State jurisdiction ends, approximately three miles from state coastlines). Just in the GOM OCS,

the MMS is responsible for over 6,000 concessions. The current MMS bonding system was

established between 1989 and 1991, after an administrative separation of the BLM. This bonding

system has its roots in the very same BLM system. During 1989 and 1991, a comprehensive

alteration of the former BLM system was made aimed at adjusting the old rules to the current

offshore sector. The establishment of the supplemental bonding rules (performance bonds) was

prepared in 1993.

The MMS bonding system consists of bond requirements in all project phases. An

estimation of ex -post costs in the concession area determines the value of the bond required.

Instruments accepted by the MMS are corporate surety bonds, U.S. Treasury Bonds that may be

negotiable at any time with a cash value that corresponds to the value of the guarantee.

The MMS asserts that will analyze any proposal for the acceptance of alternative financial

instruments, but assumes that, so far, no exceptions to the small list of acceptable instruments

were made. The MMS also reserves the right to require additional coverage in the form of

supplemental bonds at its own criteria.

4.12. THE FINANCIAL ASSURANCE SYSTEM IN THE US HARDROCK MINING

INDUSTRY (US BUREAU OF LAND MANAGEMENT)

The BLM (Hardrock Mining) is a Branch of the U.S. Department of Interior and regulates

mining exploration and production. Bonding regulations vary greatly from state to state, but

generally, bonds are required per area used. At the National level, bonds have been used since

1994, but with poor results, according to observations made during the present study. The BLM

is under intense criticism from society and NGOs (NWF, 2000; MPC, 2000). The environmental

liability is significantly high. Rehabilitation costs estimates at national level are many times

superior to the amount currently secured in the form of bonds.

Undeniably, the most problematic situation concerning the application of bonding

mechanisms among the four bonding systems studied is the BLM - Hardrock Mining. The

!54

current regulatory system is complex and allows excessive confusion among jurisdictions and

state and federal regulations.

Hardrock mining operations have the potential of causing extensive environmental and

social impacts. The BLM bonding system suffers throughout the sector, from small-scale

operations, which cause elevated damage but are not included in the bonding regulation, to large

operations which generate a great deal of rock burden, AMD, suspended particles, deforestation,

visual impacts, among other impacts.

In most cases, bond requirements are insufficient to cover all ex-post environmental

obligations, and, for this reason, do not generate any incentive for compliance. As a result, the

environmental liability in the sector is high and companies that profit from the activity can easily

exonerate themselves from their responsibilities, imposing costs on the agency. Closure costs in

mining areas vary significantly from state to state ($ 1,000 to $20,000 per each 4,046.931 m2

affected). However, if the agency is obligated to perform closure operations, or subcontract a

private operator, costs may be 50% to 500% higher. This happens mainly because state agencies,

without any kind of verification mechanism, accept the estimates offered by operating

companies. In addition, state authorities accept virtually any form of bonding instrument, and, in

some cases, even projected revenue from the project being bonded.

The BLM bonding system is under severe criticism and faces several litigious actions.

Other problems faced by the agency include political pressure against proposals for higher bonds,

excessive flexibility offered to operators, high monitoring costs (areas of difficult access), and a

historical legacy of abandoned mines.

4.13. THE FINANCIAL ASSURANCE SYSTEM IN THE US ONSHORE PETROLEUM

INDUSTRY (US BUREAU OF LAND MANAGEMENT)

The BLM (Onshore Petroleum), is a Branch of the U.S. Department of Interior and

regulates exploration, development, and production of oil and gas in Federal and indigenous land.

The agency is responsible for the inspection of over 112,000 oil and gas wells (BLM, 1992).

This branch of the BLM is a very old agency. Preliminary studies indicate that the term "aged" is

probably a suitable definition for the agency. Financial assurance has been required since early

1920's and very few alterations have been made since then. The system is based on requiring

31 1 US Acre.

155

only symbolic financial bonds, although higher bonds can be legally required. The historic BLM

policy has been of requiring bonds only to safeguard the agency against companies getting

behind in paying, or exonerating themselves of paying, their due royalties.

Currently the most complex problem faced by this branch of the BLM involves orphan

wells32. These wells were not capped, plugged, nor adequately abandoned. Other issues involve

the great number of shut-ini3, in which production may resume depending on market conditions.

The BLM bonding system is a textbook example of a financial assurance system based

solely on financial bonds, in which the only objective of the mechanism is to ensure proper and

timely payment of royalties, or, in other words, a token or symbolic value, indicating the

intention of the candidate company in complying with royalty obligations. Incentives for ex-post

environmental compliance are not provided by BLM requirements.

Bonds have been required by the BLM since 1920 (US$ 5,000 per well), when the

regulation was inaugurated. A revision of the bond amount was made in 1960 (to US$ 10,000

per well), and it remains since then. A movement for increasing this value to $20,000 was

launched around 1999. During interviews and conversations with BLM staff, it was apparent that

there is an interest of the agency in reevaluating this bond amount. However, it was also evident

that fierce opposition was encountered. Although higher bonds can be required under the current

rule, adequate performance bonds are nonexistent. It is important to emphasize that the agency

assumes an interest in higher financial bonds, but not in requiring performance bonds, which

would represent the full value of ex-post costs.

Regulators recognize that small operators often choose to default the bond instead of

assuming ex-post costs; and, with no iocentives, the irregular interruption of projects is frequent.

For this reason, the BLM also faces substantial litigious actions. Interesting enough is the fact

that the agency is aware of potential environmental complications from various forms of

contaminations caused by improper abandonment or noncompliance with ex -post obligations,

includiog mercury contamination from old manometers used to measure gas pressure, which in

the past have been largely abandoned in situ.

The BLM does not offer much flexibility in what financial instruments are concerned.

Instruments accepted are: corporate surety bonds, Certificates of Deposit, Letters of Credit, Cash,

32 Orphan wells: wells where a responsible party cannot be identified. 33 Shut-in wells: temporarily abandoned wells.

156

and Bonds issued by the Government (Treasury Notes). As mentioned, according to the current

review conducted during this study, the major BLM problem is not excess of flexibility given by

the number and forms of instruments, but lax bonding requirements (no incentive for

compliance). The number of contractual default also confirms this.

4.14. COMPARATIVE ANALYSIS OF THE FOUR U.S. BONDING SYSTEM

Although based in the very same 1920-regulation, the MMS regulation has been more

realistic and objective than the rule applied by the onshore branch of the BLM. For instance,

under the MMS bonding system:

• The lessee that cannot demonstrate capacity to fulfill all ex-post obligations, will not

obtain an operating license;

• Bonding instruments accepted are few, offering a limited flexibility for small and

independent operators. As a practical result, the participation of high-risk companies

was drastically reduced; and

• The bonding requirement, bond amount, may be reduced or increased, depending on

the risk offered by the candidate.

During the relatively short time the MMS bonding rule has been in place (since 1989-

1993), the very first case of ex-post noncompliance case occurred in 200 I. In addition, due to the

dynamic character of the offshore sector, the agency promotes some form of adjustments in the

regulation every two or three years, reflecting corrections of any forms of evasion opportunity

(loopholes) identified in the system throughout that period. With this approach, the MMS has

very little problems and regulatory costs are low. At the beginning, lessees resisted, but the

agency persevered firmly and companies adapted themselves to the stringentness of the new

requirements. During all this time, there has been only one litigious action against the MMS

(2000e).

The onshore branch of the BLM, in contrast to the MMS, bears significant liabilities that

were inherited from very old operations; in addition, the BLM has to deal with very complex

issues of leases in Federal and Indigenous lands. A great part of the BLM concessions are

marginal fields and in the hands of small and independent operators. There are some very unique

situations involving onshore projects. For instance, there are cases where a project owner (a

!57

single project owner) contracts three or four workers and starts producing onshore petroleum

(BLM, 2000). With a very generous regulation, which motivates evasion and a strong lobbying

of producers, the BLM problems are significant, such as:

• A large number of orphan wells34 in which no responsible parties can be identified,

and idle wells35, which are inactive but not properly plugged and abandoned.

• When oil prices are low, companies refuse to abandon wells (plugging) arguing that

there is no capital left to do so. When prices are high, lessees argue that they cannot

plug the wells because there are possibilities of returning to old reservoirs.

Consequently, there are plentiful idle wells.

• The BLM suffers with a number of litigious actions impetrated by lessees,

municipalities, and the public. Preliminaries analysis indicates that the BLM is in a

lose-lose situation: In order to avoid additional litigating actions and further evasions,

the agency must yield for bargaining proposals.

• Backed by a strong lobbying, any attempt to improve the current BLM legislation is

frustrated.

• Evasion of royalty payments, lack of funds for monitoring ex -post operations, and

currently, the opposition of the executive administration36 to any requirement that

might suggest "environmental costs" to oil producers.

For practical purposes, studies were concentrated on more mature bonding systems,

which could provide hands on the job information. Four American agencies were able to fulfill

this criterion and Table 4.5 identifies their main characteristics allowing an item-by-item

comparison.

Observations during this preliminary assessment indicates that among the bonding

systems studied, the MMS' s is the most efficient one. It is important to emphasize that the

offshore oil sector presents different and more favorable characteristics than the remaining

agencies and the areas under their jurisdictions.

34 1992 BLM estimations indicated around 16,384 orphan wells under the jurisdiction of the agency. A general estimation for all state jurisdiction indicated 51,043 (Source: BLM, 1995). 35 1992 BLM estimations indicated around 114,896 idle wells under the jurisdiction of the agency. A general estimation for all state jurisdiction indicated 214,894 (Source: BLM, 1995). 36 The current President of the United States, Mr. George W. Bush, is a former independent oil producer with a lax environmental record.

!58

TARJ.l< 4.< SJTR.l :TIVE • ANALYSIS OF

------------- ~~~ ~~~and Gas BL~ning MMS 'Oil and Gas

Sv<tem line 1970 1920 (! 960*1 1994 (! 970*1 1989-1993

L Performance bond L Performance Bond L !Bond

Fonn of required guarantee? 2. Contingency Fund 1. Financial Bond (depends on 2. 'tsono

3. Residual Liability jurisdiction) ! Re;idu';.iiiabili!;

Minimum amount US$ 50.000 to USS US$ 10.000 I well

<US$ 1.000 to 500.000- Financial Bond

Value of required guarantee? 100% of ex~post costs USS 25.000 I blanket US$ 20.000 100% of ex·post costs-

+ Indirect Costs bond (State) per affected 4,046.9 mz Performance Bond

US$ 150.000 I blanket US$ 35 million to US$ 150 bond (National) million - Special Fund

1. Operator (usually) Who defines bond amount? Agency & Operator Agency 2. Agency & Operator Agency & Lessee

3. Agency (tarely)

~ Adequate Insufficient Insufficient Adequate

Sureties, Cash, Escrow Accounts, Varies from State to

CDs, Letters of Sureties, CDs, Cash, State, but practically Sureties, LSAA, Third~ Accepted Instruments Credit, Treasury Treasury Notes, and all available Party Bond, and Self~

Notes, Real Estate, Letters of Credit instruments including Bonds Pool Bonds, and Self Budget Set~ Asides

Bias from

Inadequate ex-post agency, totally inadequate bond

cost estimates, large amounts, excessive

Large interest of small, AMD, abandoned number of orphan and

flexibility, excessive independent, newly-

Main Problems mines, and litigious idle wells, political

number of acceptable fanned, or marginal actions for negligence pressure, antiquated

instruments, high companies on the large

(AMD-related) and inefficient monitoring costs, high

number of small and legislation, Industry's

environmental marginal fields available.

bargain power liabilities, abandoned

min~s. etc. ~()f

Problem (I worst+ 4 Best),

2 3 I 4

=.i; ::;::;,~:~ Yes No No* Yes r:eVelOf .

svstem to th~oi,;;;;-d;~;;· High Moderate High Insignificant

Level of Low High Very High Insignificant

~ l~ft (;; th~ A•<:rlcv High High Very High Insignificant

MOStUSeJ• Surety Surety Not Kno'Ml Surety

Lea.<t u.<ed Not Known 'NO! Known Not Known

I hi~j;_;:;;i;~ the Not Known Not Known Not Known Not Known

~;;;,;:;;;, in Not Known Not Known Not Known Not Known I

"notential liahilitv Not Known Not Known Not Known

. ;~~tr: iiOf High High Very High Very Low

~ J ~el ofu.<e

~ ~ Hi•h

Level v Costs Low

159

The MMS deals with a scenario where monetary values are usually greater than in other

sectors such as hardrock mining, onshore petroleum, and coal mining. Even dealing with greater

financial responsibilities, non-compliance risks are significantly lower. These circumstances do

not take away merits from the MMS, since the agency has established and maintained an efficient

and viable bonding regulation. For instance, during the last 9 months of 200 I, the MMS branch

office in the GOM region, handled 123 decommissioning applications. During 2002, 196 new

structures were approved and placed in production areas. The same branch oversees over 6,000

concessions and around 5,000 installations. Any modification (engineering, logistic, etc.) must

be approved by the agency, and usually this process takes only two or three working days. The

most interesting aspect is that a single MMS employee is responsible for the entire

decommissioning sector (new structure approvals, shallow areas, and decommissioning) for the

entire GOM Region. A small group handles pipelines (plugging and decommissioning) and a

third group handles well plugging and abandonment. This allows very lean regulatory costs.

4.15. REGULATORY ISSUES

Do bonding requirements discriminate against small, newly-formed, and independent

lessees? In order to obtain permission (or license), to explore, develop, and produce within

public areas, a lessee (or operator) must sign a comprehensive contract acknowledging all ex-post

environmental obligations. If a candidate company, a potential lessee, cannot demonstrate its

capacity to fulfill such clauses, the regulatory agency as the designated keeper of this public

good, is responsible for stopping this company from obtaining the lease. Allowing high-risk

lessees would be negligence and, in countries where this criterion is not being applied,

governments have been inheriting huge financial liabilities. Otherwise, oil companies would be

risking precious natural resources in exchange for a profit opportunity. Bonds are aimed at

guaranteeing the performance of operations that the lessee has already agreed on completing, as a

basic condition for operating in this sector. If an oil company cannot demonstrate its financial

capability to cover pre-established contractual obligations, it would not be financially equipped

prevent, mitigate, remediate or fmancially compensate damages that may occur during the length

of the project, consequently, it would be demonstrating that it would not be able to comply with

contractual obligations.

!60

The efficiency of a bonding system also depends on the costs required to maintain the

regulatory role. In order to obtain some forms of bond, financial institutions will submit

candidate companies to stringent underwriting processes. These instruments allow significant

regulatory cost savings. Bond-issuing fmancial institutions have a direct interest in monitoring

the financial health of their clients, operating companies; and, in case lessees default, financial

institutions will have to assume all their client's ex -post obligations.

Instruments offering superior flexibility and low direct costs, most of the times, will cause

high indirect costs or higher risk to the regulatory agency. Regarding regulatory costs, gathering

information maybe one of the most costly activities forregulators (the "information burden"):

• Establishment of a database system to assist in the estimation and comparison of

operations costs;

• Assessment of new technologies and practices within the sector;

• Hiring or forming experts in the areas of interest (i.e. bonds, decommissioning,

insurance policies, etc.);

• Assessing and monitoring the financial health of lessees and bond-issuing institutions

during the length of the project.

The applicability of bonding system must consider ongoing projects and projects near the

end of their lives. For instance, how to enforce bonding requirements from a lessee operating a

marginal project? What would be this lessee's capacity to fulfill recently established ex-post

obligations? What to do if funds necessary to fulfill ex,post obligations are higher than potential

revenue? Should a different approach or a case-by-case evaluation be applied under these

scenarios?

Some argue that an oil company that has been acquiring financial resources throughout its

life must have available capital to fund even newly enforced ex-post obligations, whatever they

maybe.

Idle wells can be a source of great problems within the sector. Usually, agencies establish

a period in which a well can be temporary inactive before permanent plugging and abandonment

is required. A possible solution for this scenario would be offering incentives such as tax

reduction and royalty relief for marginal producing projects, allowing them to be active even

under unfavorable market conditions. This approach would extend the life of fields, reduce

161

impacts of ex-post operations, increase total oil output, and leverage investments within the

sector.

In the specific case of Brazil, some public construction projects reqmre bidding

participants to contract insurance policies to guarantee the performance of projects. It is

probably possible to use the same legal basis to promote the requirement of environmental

insurance to be used as performance bond, although, as stated previously, there are instruments

more efficient than insurance policies. Instruments under the escrow accounts category may

pose a problem, since the legislation forbids governmental institutions of owning joint accounts

with individuals. This same principle would limit the application of other instruments such as

some pool bonds categories. Other forms of financial guarantee instruments currently in use in

Brazil are LOCs and CDs.

This study has identified a VIew in which some sectors of the industry believe that

performance bonds are aimed at super compensate the regulatory agency in the event of default.

Experience shows that regulatory agencies require bond liquidations as a very last alternative.

The liquidation of a bond brings excessive complexity to regulators, who will have to assume a

problematic project and fmd a subcontractor willing to undertake an unfmished and uncertain

project.

Another legal argument against the application of bonding instrunients is that it deprives

the lessee of a basic universal legal principle, which is: innocence is presumed and guilt requires

proof However, in the case of economic activities such as upstream petroleum projects, the

probability of ex -post damage, or guilt, is 100%. Ex -post damages are indeed expected as a

natural outcome of the activity, and then, before such activities are permitted and licenses are

granted, a guarantee for the availability of funds to cover ex -post damages must also be of I 00%.

Any environmental problems erupting after ex-post obligations are met should be

denominated "residual responsibilities". Lessees surely will require from regulators some form

of guarantee that once ex-post obligations are met, there will be an endpoint, a ticket out, to

liabilities, and, mainly, there will be no post-closure liabilities.

For society, oil companies will always be responsible for environmental problems, direct

or indirect, and during or post-production. The legal debate involving residual liabilities is very

complex and divisive. Large and historical transnational companies have intangible cost

incentives to prompt and voluntarily deal with residual liabilities. Currently, a negative public

162

perception may cause considerable cash flow impacts for these large corporations. On the other

hand, small and marginal companies would not have the same incentive, and the agency would

probably have to fund post-closure mitigating operations.

The oil industry has been seriously affected by environmental problems. Legislators have

heard the public outcry and transferred their stress to regulations. Contacts made with

representatives from large oil companies, do not feel they need bonding requirements to be

motivated to fulfill ex-post environmental obligations, although agree that bonds are necessary to

protect government and taxpayers from future liabilities left by other class of operators.

Under stringent regimes, the industry complains that lessees with proven financial

capacity should be authorized to use soft bonds, and only more vulnerable lessees would be

obligated to provide hard bonds. The financial sector in the United States indicates that in well

elaborated regulations, such requirements would not offer great problems to large historical

companies. However, agencies that offer excessive flexibility accumulate a great number of

litigious processes in which the public requires to know why sufficient resources were not

available to guarantee the performance of ex-post operations.

Some smaller companies prefer to allocate a certain amount of capital in collateral

accounts receiving interest revenues rather than buying a product that requires the payment of

nonrefundable premiums and fees. A large company undertaking a large project would prefer to

acquire an insurance policy or a surety bond in order to receive fiscal advantages and face less

significant opportunity costs.

There is a common feeling among most experts, and also some regulators, that an

accurate method of estimating ex -post operation costs and establishing bonding requirements, is

of greater importance than defining the ultimate bonding instrument. Amongst large oil

companies, there is also a general belief that term and conditions of licenses are more important

than bonding requirements. Nevertheless, regulators must demonstrate to society that an

adequate financial protection is available to safeguard taxpayers from future liabilities.

163

CHAPTER V- FISCAL TREATMENT- DECOMMISSIONING & BONDS

Are ex-post expenditures tax-deductible? What kind of fiscal incentives are available to

improve investments on innovative technologies and processes aimed at improving environmental

performance of end-of-leasing activities and reducing ex-post expenditure?

Are there fiscal incentives for bonding instruments? Should forther incentives be

provided to instruments in order to reduce financial impacts on project cash flows? Is fiscal

planning an important issue for decision makers considering bonding options?

5.1. DECOMMISSIONING FISCAL TREATMENT- DISCUSSION

Fiscal planning becomes more important as economic incentive mechanisms are

increasingly being adopted by regulatory agencies around the world. As competition increases,

environmental regulations toughen, and projects get marginal, companies are increasingly

expected to reduce, as much as legally possible, government earnings in projects. According to

YOUNG and MCMICHAEL (1998), the most significant negotiable factor that affects the

performance of the project is income tax.

Future liabilities, such as costs to meet decommissioning obligations, must be carefully

considered in company's fmancial statements. Companies must consider how to anticipate such

expenditures and how, whenever possible, to apply them in each year's accounts. Lower

estimations of cost to meet ex-post obligations may provide better 1\'PVs (cash flow results).

Lower tangible ex -post costs may provide better profits. The problem is that higher l';'PV s lead to

higher corporate taxes. In addition, higher decommissioning estimates, may lead to higher

financial assurance requirements.

Companies are not the only parties impacted by high ex -post costs. Such costs involve

direct and indirect impacts on governments, taxpayers, and society as a whole. Current tax

structures determine that governments, and consequently taxpayers, bear part of the cost for

decommissioning, providing tax relief for oil companies. In some countries where the debate on

decommissioning related issues is more advanced, the matter of charging the taxpayer for

decommissioning operations of private oil companies is being severely questioned. However,

most regimes do provide legal basis for dividing the costs of meeting ex-post obligations between

the state and the private sector. In some countries, the government bears the majority of the

financial responsibility, as it is the case of Norway.

164

Deduction rates may vary significantly from country to country. In the UK, for example,

oil companies are taxed on their earnings from oil and gas production but since decommissioning

expenditures are allowable against taxable earnings, the UK government loses revenues

equivalent to 50% to 70% of ex-post costs (PROGNOS, 1997).

In Norway, government covers the greatest part of platform removal costs and companies

cannot deduct removal expenses in their corporate income tax (NPD 1999; PHILLIPS, 1999b).

Decommissioning obligations are not subjected to ordinary tax handling. They are kept outside

the tax system. In any case, other costs involved in the decommissioning of installations are fully

deductible.

In 1975, Phillips Petroleum Norway claimed deduction for future removal costs. That

was when NPD established its first special tax rule for decommissioning costs: "based on the

principle of taxation, all costs are deductible but due to the uncertainties involving anticipating

costs, no tax deduction for future costs are allowed" (PHILLIPS, 1999a; PHILLIPS, 1999b;

NPD, 1999).

The Norwegian Removal Grant Act (25/04/1986) states that when installations are to be

removed, the State will bear a share of removal and disposal costs. Other ex-post obligations are

not included in this cost sharing treatment. This Act is only applicable for expenses directly

related to the removal and disposal of installations. Other ex -post costs such as preparation,

assessments, well plugging, etc., are considered legitimate operation costs and are deductible

(NPD, 1993).

A better way of understanding this system is: "State's percent share is equal to the

average tax rate for each licensee over the lifetime of an installation" (PHILLIPS, 1999b ).

Payment of tax before 1975 is not included. The State share for removal costs are based on the

estimates of each licensee. The State contribution cannot exceed accumulated paid taxes. The

final decision is not taken by NPD, but rather by the Ministry of Finance, which defines removal

costs. This calculation will include all years from the development of the platform up to its

removal and disposal. The calculation does not include taxes paid when the platform was not

installed. For instance, if the average corporate tax paid during the 20 years of operations of a

platform was 75%, the Norwegian government will pay for 75% of the disposal costs. One

problem that can be anticipated is, for instance, if at the time of the decommissioning of a

165

specific platform the tax rate is around 80% and the average was calculated at 75%, the company

will loose 5% on possible deductions.

Even losing considerable funds by allowing tax relief for ex-post expenditures,

governments will earn tax revenues from income tax of workers and other several levies imposed

on companies involved in ex-post environmental activities. In addition, by allowing fiscal

incentives governments may significantly reduce the risk of noncompliance and undesirable

environmental liabilities.

Within this context, parameters such as decommissioning options (total or partial platform

removal) may cause significant fiscal effects. For instance, North Sea government's expenditure,

or the amount by which tax receipts are reduced as a result of decommissioning, amount to about

US$ 6.3 billion in the case of total removal and between US$ 3.8 billion and US$ 5.8 billion for

partial removal. Consequently, possible "savings" offered by partial removal options are

somewhere between US$ I billion and US$ 2.5 billion up to the year 2020, just for North Sea

projects. The income tax revenue generated by new jobs and related decommissioning activities,

total about US$ 1.4 billion for total removal, which is US$ 0.1 billion and US$ 0.3 billion higher

than in the case of partial removal (PROGNOS, 1997).

According to these numbers, considering total and partial removal options, taxpayers from

North Sea producing countries would save between 8% to 44% (US$ 15 million to US$ 95

million) per year, if partial removal options were to be adopted for all installations. If total

removal is adopted, taxpayer from North Sea producing countries will be paying for

decommissioning up to the year 2020 between US$ 400 million to US$ 2.2 billion.

The fiscal environment may also contribute to the adoption of even more improved

practices. KAPOEN (200 1) suggests that in order to encourage the reutilization of redundant

offshore installations and components, depreciation should not only apply to new business assets.

In addition, authorities should accept that remaining partners could rollover their tax bookvalues.

Fiscal incentives may help improve the market for used structures, mainly to be used in small

and/or marginal projects.

Therefore, for most tax regimes, ex-post environmental obligations, including

decommissioning costs, are ordinary and necessary expenses. In general, such expenditures are

tax-deductible only when services have been performed and payments have been made. When

progressive abandonment is adopted, the same rule applies. Deductions are usually not allowed

166

for decommissioning activities carried on during non-income years (when production has

ceased). In such situations, companies are usually allowed to carry a "credit" towards a future

project, as it is the case in the current Brazilian fiscal regime. Some regimes offer provisions

allowing some type of "anticipated tax-deduction provisioning" spread over a period during

revenue-producing years. The approximate goverrnnent participation in Brazil is around 65%,

not including bond related expenditures (BARBOSA, 2001). Figure 5.1 shows the profit-split

between the goverrnnent and the producing companies.

COMPUANCE?

NO

~ GOVERNMENT l Interest revenue. Taxes, premiums, EARNINGS

fiscal incentives ANANCIAL tees. levies · .. ·•··

GUARANTEE

= I. i>-.. ~ . . · > !

= YE

ii ., ~

"' ! ~ ~ ~ e. Investments ..., GROSS I 8 -£:>-4 • Profit Split r REVENUE

s

~ :! · ... · .·• r! = Taxes. bonuses, " ;;

t "' .3 special participation -o 3-e ~ 'i 7 ~ ~g. 5

0

CORPORATE l EARNINGS .f

· ..

Figure 5.1. A simplified fiscal system including bonding system.

5.2. BOND FISCAL TREATMENT- DISCUSSION

Within financial assurance regimes, companies depositing funds into escrow accounts

pledged to the goverrnnent (bonds), no deduction is available until the company loses ownership

of the funds. However, within most financial assurance regimes, if a company pays fees or

premiums to keep surety bonds or environmental insurance po Jicies, such expenditures would be

amortized over the time period covered by the bond.

167

In general, the rule for deductibility is that the expense has to be an ordinary and

necessary business expense and not a capital expenditure (IRS, 1999). The fact that a company is

contractually liable for ex -post expenditures or provides anticipated funds to guarantee such

obligations (bonds), does not entitle it to deduct the cost of such services before they have in fact

been performed.

In Canada, Japan e South Africa, collateral bonding instruments such as escrow accounts

that allocate upfront capital are also conferred with deductions. However, any revenue awarded

from financial application of allocated funds (i.e. interest from escrow accounts) is subjected to

ordinary taxation. Under more mature bonding regimes such as in Canada, there is a common

notion among specialists and regulators that offering a net fiscal incentive is better than risking

inheriting ex -post environmental liabilities from the mining and oil sector. Indeed, a very

interesting study proposal would be the assessment of potential fiscal incentives for financial

assurance instruments.

On the other hand, some other aspects must be considered. Would further fiscal

incentives reduce or eliminate the main motivation for compliance with ex-post obligations? If

deductions are extended to cash collateral accounts, for instance, the main motivation for

compliance, which is "doing it right in order to get the bonded money refunded", may be

annulled. As a result, if a company can get its allocated capital back through tax deductions

before the end of the project, what kind of incentive is left for compliance? Three variables can

act as catalytic factors within bonding regimes: flexibilities demanded by the industry,

requirements established by regulators, and risks offered by flexibilities. Providing fiscal

incentives could be considered a form of flexibility. Figure 2.3 illustrates the dynamics of the

bonding system where, due to public pressure, regulators establish stringent performance bond

requirements generating direct and indirect economical impacts on the profitability of petroleum

projects. The industry demands flexibilities that may come in the form of softer instruments,

fiscal incentives, or lower bonding estimations. These flexibilities increase the risk of

noncompliance triggering public concern and involvement, closing a very common cycle.

168

CHAPTER VI- DECISION TOOLS: ECONOMIC MODELS

How to anticipate and reduce the impacts of environmental regulations, more specifically,

financial assurance requirements, upon the profitability of offshore petroleum projects? Answer:

developing decision tolls and economic models for managing oil project decisions involving ex

post and financial assurance mechanisms, providing a way to anticipate economic impacts of

several bond alternatives.

In this chapter, two articles are presented. The first article offers an algorithm in order to

assist decision makers, both regulators and industry, evaluate potential NPV impacts of financial

instruments used to satisfY bonding requirements. The second article deals with potential

financial impacts of bonding instruments on offshore oil projects.

I. REFERRED ARTICLE II- Natural Resources Research, submitted in 2003

TITLE: A.~ EXPLORATORY ANALYSIS OF THE ENVIRONMENTAL BONDING

SYSTEM FOR UPSTREAM PETROLEUM PROJECTS

AUTHORS: Doneivan F. Ferreira<!)*; Saul B. Suslick<I)(Z); Paula C. S. S. Moura(3>.

(!)Department of Geology and Natural Resources - State University of Campinas (UNICAMP),

P.O. Box 6152, Campinas, SP 13083-970 - BRAZIL; (!)Center for Petroleum Studies

(CEPETRO), P.O. Box 6052 Campinas, SP 13083-970 - BRAZIL; and <3>Department of

Mathematics, Statistics, and Computer Sciences - State University of Campinas, P. 0. Box 6065,

Campinas, SP 13083-970-BRAZIL.

ABSTRACT

This paper deals with potential financial impacts of different bonding instruments on oil projects.

An algorithm was prepared in order to assist decision makers, both regulators and industry,

evaluate potential NPV impacts of financial instruments used to satisfy bonding requirements.

Instrument option is the main variable for the proposed modeL The user will be able to chose

between four commonly used instruments (letters of credit, prepaid collateral closure accounts,

leasing specific closure accounts, and ex-post insurance policies). This study includes

169

simulations for three producing fields of different reserves (9 MMbbl, 53 MMbbl and 148

MMbbl), where four financial instruments, in addition to a "no instrument" scenario, are tested

under a proposed bonding regime. Sensitivity analysis of Net Present Value and Government

Take value indicate ex -post insurance policies and letters of credit cause fewer impacts yielding

significantly better payoffs. Preliminary simulations also confirm that small projects can be

severely affected when collateral account instruments are used.

KEY WORDS: Financial Assurance; Economic Model; Bonds

6.1. INTRODUCTION

Worldwide, several countries have adopted or are in the process of adopting financial

assurance requirements (bonds). A number of natural resources agencies, petroleum and mining,

have already established some form of bonding system aimed at ensuring the performance of ex

post environmental obligations (end-of-leasing or closure requirements). Such systems can be

seen in operation in countries such as the United States, Canada, the United Kingdom, Australia,

and Brazil, among others (OSM, 1987; YOUNG, 1996; JAMES, 1997; MMS, 2000; OSM,

2000b; FERREIRA and SUSLICK, 2000; DTI, 2000a; ANP, 2000b; UNICAMP/CEPETRO,

2001).

The present study includes cash flow simulations and sensitivity analyses of four

commonly used financial instruments: Letters of Credit, Prepaid Collateral Closure Accounts,

Leasing Specific Closure Accounts, and Ex-post Insurance Policies. Denominations for bonding

instruments can vary significantly.

The first section of this paper provides an overview of bonding systems. Section two

describes the methods, algorithms, and variables for the model. It also includes a brief

explanation of the fiscal parameters used. Section three offers an analysis of the data resulting

from these preliminary Petrobond simulations.

6.2. BONDING SYSTEMS

Current attempts of extending the lives of mature fields and turning small and marginal

fields into profitable projects has attracted the interest of a number of risky small and recently

established, and, possibly, marginal and spurious companies. Bonds come as a response to

170

environmental liability concerns, aimed at reducing the risk of noncompliance with ex -post

environmental obligations (e.g. plugging, abandonment, decommissioning, reclamation).

Bonds are hybrids of market mechanisms and command and control regulations. Despite

not being pure market instruments, bonds force companies to internalize ex -post environmental

liabilities directly into their cash flow accounting, making costs explicit to shareholders.

Bonding systems currently in use include one or two of the following bond categories:

Financial and Performance bonds. A financial bond does not guarantee the performance of an

obligation. Instead, it can be compared to a token pledging, under the penalty of loosing no more

than the amount bonded, the candidate's intention of keeping all financial commitments (e.g.

timely payment of royalties and rents, honoring bids, etc.). A performance bond, in contrast,

guarantees the performance of all closure obligations. In case of insolvency or default, the

amount bonded will be available to the agency to perform all closure operations, as contractually

required.

Bonding instruments can come in several forms with unique attributes and requirements.

Some forms of bonds are pledged assets of oil companies (cash, securities, real estate, escrow

accounts, etc.); performance guarantee of a project (surety bonds); securities issued by insurance

companies, banks or other financial institutions; some are instruments that indicate the deposit of

cash (certificates of deposit) or the existence of a line of credit (letters of credit) (BRYAN, 1998;

FERREIRA and SUSLICK, 1999). Other common forms of bonds are: self bonds (a type of

fmancial test or balance sheet test), trust accounts; other forms of bank guarantees, cash bonds or

cash deposit certificates, cash trust funds, corporate guarantees, parent company guarantees, other

forms of third-party guarantees, deposit of securities, financial reserve, and security agreements.

Four commonly used instruments were selected and tested by the proposed model. The

choice of these instruments was primarily based on their applicability under the current Brazilian

legal framework, although it can be applied to any other form of concession contract. These

instruments are briefly described below:

• Prepaid Collateral Closure Account (PCCA): instrument option PCCA is a three

party irrevocable agreement. The lessee transfers assets to a financial institution (trustee)

to be managed in behalf of a third party (the regulatory agency). The full amount of the

bond must be deposit at once when the account is established. This collateral account

cannot be released without the prior approval of the agency.

171

• Leasing Specific Closure Accounts (LSCA): option LSCA works like option PCCA,

but instead of requiring upfi:ont bond disbursement, it allows the spreading of payments

during a pre-determined period (usually four years), or until production reaches 80% of

the recoverable reserves; whatever comes first. Since the application of option LSCA

depends on data from recovered reserves, it is only applicable to oil producing phases

(development/production).

• Letter of Credit (LOC): option LOC is an instrument of collateral guarantee. A

financial institution establishes a line of credit in behalf of the lessee guaranteeing the

payment of the bond amount to the agency in case of default.

• Ex-post Insurance Policy (EIP): option EIP transfers liabilities to an insurer, which

becomes the principal payer. The insurance policy will be maintained over the entire life

of the project. The bond will be released only upon the fulfillment of all closure

obligations.

6.3. METHODS

In order to perform cash flow calculations simulating a variety of oil projects scenarios

under different bonding regimes, an algorithm (named PETROBOND) was prepared in Visual

Basics (version 6.0) enabling decision makers evaluate potential impacts of financial instruments

used to satisfY bonding requirements. This algorithm was developed for the Brazilian National

Petroleum Agency (ANP) allowing the handling of operational variables, permitting realistic

simulations taking into consideration oil and gas production profiles, costs, investments, closure

costs, estimated life of projects, estimated oil and gas reserves, and market variations. For further

calculations, results are displayed in Microsoft Excel spreadsheets. Figure 6.1 shows the general

algorithm layout.

Three categories of input variables are used in the proposed algorithm: (I) operational, (2)

financial, and (3) bond-related. Under the "operational" category, the user is required to provide

operation parameters such as production, operational costs and capital expenditures, project life,

and field characteristics. Appendix C Tables C.l, C.2, and C.3 provide a thorough description

of all algorithm variables. Under the "financial" category, the user is asked to provide

information on the applicable market scenario, fiscal regime, and other government contributions.

172

Under the "bond-related" category, the user is asked to define the desired bonding rule (an

existing or theoretical system).

( MAIN ) ~ .[]. FILE

(Option to create, INPUT alter or save

(Enter Operational, Finance parameters) -and Bond parameters)

~ .[]. Economic Analysis

lNPV &GT)

.[]. Bonding

Instrument

.[].

Sensitivity Analysis

Figure 6.1. Macro-structure for the Petrobond Algorithm.

The proposed model incorporates the main variables of an ordinary upstream petroleum

project (oil price, operational costs, investments, oil type, and production schedule) determining

the ideal rate of royalty relief for an array of input combinations. Sensitivity analyses are also

incorporated into the model in order to test all instrument options, and potential impacts caused

by other input variables.

A general description of bonding mechanisms within some phases of ordinary upstream

oil projects is explained bellow.

Since there is no environmental risk involved in the bidding phase, the user may opt to

require (1) no bonds, or (2) a single fmancial bond. Choices are made by keying in values inside

the input variable window (zero to switch bonding requirements off, and the desired bond amount

to switch requirements on). In the case of compliance, bonds are reimbursed to the lessee or

redirect towards the next project phase (exploration phase).

173

In the exploration phase, as illustrated in Figure 6.2, the user may opt to require (1) no

bonds, (2) a single fmancial bond, (3) a single performance bond, or ( 4) a combination of a

financial bond and a performance bond. If the lessee decides not to develop the project, all

exploration sites must be properly "abandoned", in accordance with closure contracts. In the case

of compliance, the bond is released and/or reimbursed to the lessee. Otherwise, if the lessee

decides to develop the project, the bond may be reimbursed or redirected to the next phase of the

project (development/production phase).

Begins

Bond is : Reimbursed

~\~\ Exploration ·~,.. Exploration '\----l Exploration

\:::::~) \~' LI_P_ro_c•_•_•--"

Decides to Develop?

Figure 6.2. Diagram for the exploration phase.

< c M

Goes to the I nextphase +

f..---_J Leasing Area is returned

Yes

Compliance?

No

Forfeiture

Similarly to the exploration phase, for the development/production phase the user may

choose to require (I) no bonds, (2) a single financial bond, (3) a single performance bond, or ( 4) a

combination of a fmancial bond and a performance bond. All ex-post closure obligations must be

satisfactorily met before development/production bonds are released or reimbursed.

Figure 6.3 illustrates the closure and post-closure phases. In the case of compliance,

bonds are released or reimbursed. In the case of noncompliance, bonds are forfeited and the

agency takes all required steps to ensure compliance with all end-of-leasing obligations. The user

may decide on requiring a post-closure extended guarantee. In this case, the

development/production performance bond is withheld for a post-closure period of monitoring

(e.g. 6 years). After this period, if there are no incidents, the bond is finally released and

174

reimbursed. Some bonding instruments may come with an additional guarantee for residual

liability (e.g. some surety bonds).

,----------------------------------------------------------------------------------------------------------------~ ' ' i (A) ! : : ! Closure !

Compliance? !Begins Process ' ' ' ' : ' ' ' ' ' ' ' : ' ' ' ' : ' ' ' ' : '

Yes

I Yes

Agency requires

extended guarantee?

No

L---------------------- ---------------------------------- -------------------------------------------------No

Leasing Area is returned

Bond is Reimbursed

End

Forfeiture

:---------------_--_--_-_-J_--_-_--_--_----------1------------------------------------------------t---------------------l

:,'(B) ' ! 1 Waiting , 1 No : !Begins Process l

(years?) ,

Yes

•

No

Yes

i Corrections! :----·( Compliance? )~----

' : ' ' ' ' ' ' ! ' ' ' ' : : '

' ' ' ' ' ~---------------------------------------------------------------------------------------------------------------2 Figure 6.3. Diagram for the Closure and Post-Closure phases.

Simulations

The performance of the Petrobond algorithm was tested on three producing fields with

reserves of 9 MMbbl, 53 MMbbl, and 148 MMbbl. In order to assist decision makers in selecting

the most appropriate bonding instrument, Petrobond offers:

175

• Applicability, allowing the control of variables and manipulation of parameters;

• Flexibility, allowing the application of all options independently or combinations of

options;

• Versatility, allowing the reproduction of a particular regulatory framework;

• User-friendly, providing help menus for user not acquainted with all aspects of

bonding systems;

• Expediency, allowing the evaluation of best instrument performance under the

perspective of regulators or the industry.

Table 6.1 indicates project parameters for all simulations. The following describes the

hypothetical38 bonding regime proposed to rule algorithm simulations performed under this

present study:

Financial bonds are required in every phase, for all projects. Performance bonds are only

required in the exploration and development/production phases. Bond amounts are indicated on

Table 6.2. Post-closure operations will not be required; consequently, extended guarantees to

cover eventual residual liabilities will not be necessary. For all simulations, it is assumed that

lessees fully comply with all end-of-leasing and bonding requirements (no project default; no

bond forfeit). Regarding bond amount calculation, the agency requires a 15% bond increment to

cover indirect costs, such as third-party profit and management fees, in case of default.

All project cash flow simulations are carried out under an identical hypothetical bonding

regime. Base-case costs for closure operations are indicated on Table 6.2.

For all simulations, production starts at "Year One" (since some tax categories depend on

production, this assumption does affect government earnings). In addition, "end-of-project"

coincides with "end-of-production".

Even after complying with all bonding requirements, oil companies must disburse out-of

pocket funds to pay for closure operations at the end of each phase. Bonds are released when

bonded activities have been satisfactorily completed (in the case of collateral accounts, options

PCCA and LSCA, bonds are released and refunded).

38 The proposed scenario is based on proposed rules for the Brazilian bonding system, but can be applied to any concession modeL

176

TABLE 6.1. PROJECT PARAMETERS

Items

Field Characteristics Oil Reserves (MMbbl) Gas Reserves (MMBoe) Oil Type ('API)

General Characteristics Exploration Period (years) Development Period (years) Production Period (years) Water Depth (meters)

Costs OpEx (US$/boe)

Investments CapEx (US$/boe) Depreciable Value(%)

Government Take Royalties (%) COFINS (%) PIS(%) CIT(%) BID(MMUS$) CSLL(%) PE(%) Rent Area (Km2

) (for all phases) Rent - Exploration Phase • Rent (US$/Km2

)

Rent - Development Phase • Rent (US$/Km2

)

Rent - Production Phase • Rent (US$/Km2

)

Market Parameters

Field A

9.00 0.00

1.0 1.0

12.0 1000.0

2.25

2.50 65.00

10.00 3.00 0.65

25.00 0.50

12.00

* 400.00

125.95

251.91

1259.54

Inputs Field B

53.00 0.00

1.0 1.0

16.0 1000.0

2.25

2.50 65.00

10.00 3.00 0.65

25.00 0.50

12.00

* 400.00

125.95

251.91

1259.54

Field C

148.00 0.00

1.0 1.0

21.0 1000.0

2.25

2.50 65.00

10.00 3.00 0.65

25.00 0.50

12.00

* 400.00

125.95

251.91

1259.54

Oil Price (US$/BBL) 21.00 21.00 21.00 Gas Price (R$/m3) 0.13 0.13 0.13 (*) Special Participation based on recovery volume, reservoir location (onshore/offshore), and depth (when offshore) according to a differentiated rate table.

Based on an exploration project, the lessee submits a closure plan to the agency. The

agency then establishes a performance bond requirement that should be sufficient to cover

closure costs relative to potential ex-post damage generated by exploration activities. If the

lessee decides to proceed and develop the project, a development/production plan is submitted

along with a closure plan. The agency then establishes a performance bond requirement that

177

should be sufficient to cover closure costs relative to potential ex-post damage generated by

development and production activities. Under the present study, for comparison purposes, all

projects will be developed; therefore, all phases of a successful petroleum project will be present.

TABLE 6.2. BOND PARAMETERS

Items Inputs

Field A Field B Field C

Bid Phase Instrwnent Type LOC LOC LOC Financial Bond Amount (MMUS$) O.Q2 0.05 0.05 LOC Rate(%) 3.50 3.50 3.50

Exeloration Phase Closure Costs (base case) 1.00 2.00 2.00 Financial Bond Amount (MMUS$) 0.05 0.10 0.10

• Instrwnent Type LOC LOC LOC Performance Bond Amount (MMUS$) 1.15 2.30 2.30 • Instrwnent Type LOC LOC LOC LOC Rate(%) 3.50 3.50 3.50

Develoement/Production Phase Closure Costs (base case) 2.00 15.00 15.00 Financial Bond Amount (MMUS$) 0.50 0.50 0.50 Performance Bond Amount (MMUS$) 2.30 17.25 17.25 • LOC Rate(%) 3.50 3.50 3.50 • PCCA Rate(%) 5.50 5.50 5.50 • LSCA Rate (%) 5.50 5.50 5.50 • EIP Rate(%) 3.00 3.00 3.00 Discount rate based risk evaluation(%) 0.00 0.00 0.00 Credit Rating Top Top Top

It is assumed that all lessees have top credit and performance rating. Therefore,

instrument options LOC and EIP will be offered reasonable premium rates, low fees, and, in

addition, supplementary collateral guarantees will not be required39•

The terminology "Government Take" (GT) herein applied comprises several taxes and

levies including, Signature Bonus (BID), Royalties (ROY), Special Participation Compensation

(PE), Rental Area Fees (Rent), social contribution for funding Social Security (COFINS) and

Workers Social futegration Programs (PIS), Corporate Income Tax (CIT), and Social

Contribution over Net Profit (CSLL) (Table 6.3).

39 Letters of credit are very complex tools and fmancial institutions tend to be very conservative in tbe underwriting process. Collaterals are often required.

178

TABLE 6.3. FISCAL CALCULATIONS

Gross Income = total income from oil and natural gas sale

{

• Royalties L - Operation Costs

ess - Closure Costs (if allowable against tax) - Depreciation

Taxable Basis = Gross Income- Amortization

Plus { + Bond Interests (for PC CAs or LSCAs)

Investment Credits - Financing Interests - Fiscal Loss Compensation

Less -BID -Fees (for LOCs)

- Premiums (for EIPs)

Note: the following taxes are calculated: PE, P&D (1% of the gross income, according to production limits obeying PE criteria). CIT, and CSLL (these calculations take into consideration loss compensation of up to 30% and deduction of 113 ofCOFINS annual values.

In most countries closure costs are treated as operational costs (ordinary and necessary

expenses), and, for this reason, can be fully deducted. This issue of charging taxpayers for

closure operations of private oil companies is being questioned in some countries (PROGNOS,

1997). However, most regimes do provide legal basis for sharing the costs of meeting end-of

leasing obligations between the public and the industry. In general, closure expenditures are tax

deductible only when services have been performed and payments have been made. The same

rule applies when progressive closure approach is adopted. Under some regimes, deductions are

not allowed for closure activities carried out during non-income years (when production has

ceased). In this case, companies are allowed to carry a "credit" towards future projects, as it is

the case in the current Brazilian fiscal regime (ANP, 2000b).

Under most fiscal regimes where bonding systems are currently in use, deductions are not

available for companies allocating funds as collateral guarantee (e.g. PCCA and LSCA).

Deductions are only available when the lessee loses ownership of funds, closure services have

been performed and payments have been made. However, if a company pays fees or premiums

to keep bonding instruments in place (e.g. LOC, LOC and surety bonds), expenditures may be

amortized over the period covered by the bond. The basic rule is that, only ordinary and

179

necessary business expenses are deductible; capital expenditure is not. Being contractually liable

for closure operations and issuing bonds (in anticipation) to guarantee such operations, does not

entitle companies to deduct cost of services before they are actually performed (FERREIRA and

SUSLICK, 2001; BARBOSA, 2000).

Simulations performed under this proposed model were ruled by the current Brazilian

fiscal regulation. Figure 6.4 provides a visual analysis of the proportion of the main cash flow

components.

Special Participation Compensation (PE) is an additional financial compensation paid by

lessees in fields of high productivity or high profitability. Its calculation is based on the gross

revenue from production minus royalties, exploration investments, operational costs, closure

costs, depreciation, and other tributes required under the current regulation (IR, COFINS/PIS)

(BARBOSA and BASTOS, 2001; BARBOSA, 2001). Rental fees are based on the area leased

(in Km2). Cash flow calculations for government participations are illustrated on Table 6.3.

For the specific case of instrument options EIP and LOC, premiums are deducted for

CSLL and CIT calculations according to the allowable deduction rate supplied by the user.

Interest earnings from instrument options PCCA and LSCA are subjected to CIT. For all

simulations, interest earnings are paid as earned.

6.4. Al~AL YSIS

The traditional discounted cash flow method (DCF) was used to measure the profitability

of projects. The standard indicator NPV (Net Present Value) was used to measure the returns

obtained by the firms. The ratio NPV by recoverable volume (the weighted NPV per barrel

discounted at 15%) was applied for assessing the relationship between volume and value for

future stand-alone comparisons. Government Earnings (GT) was also used as basis for

comparison. The total net production was estimated excluding the volume of re-injected oil and

natural gas or petroleum consumed during production operations.

The following approaches were used on the algorithm Petrobond for evaluating the results

obtained in the simulations: (1) company's perspective: the preferable choice should have the

highest payoff (1\'PV); and (2) government's perspective: the preferable choice should comprise a

combination of reasonable government earnings to maintain the regulatory role, an adequate

guarantee to ensure performance, and a cost considered tolerable by the industry.

180

Financial instruments are used here to determine the sensitivity of the variable "Bond

Option". This study includes five simulations for each of the three oil-producing projects: one

simulation for each bond scenario (NoBond, PCCA, LSCA, LOC, and EIP) with recoverable

reserves ranging from 9 MMboe to 148 MMboe (million ofbarrcls of oil equivalent).

Gross PIS/COFINS

+ Income

CapEx

Figure 6.4. Comparison diagram indicating taxes and other government contributions. Based on the proposed fiscal rnle currently adopted in Brazil (SCHIOZER. 2002 -MODIFIED).

6.5. RESULTS AND DISCUSSION

Bonding instruments behave differently in terms of allocation of valuable initial resources

and in the way taxes and levies are collected. Instrument choice may impact, with distinct

intensity, various sections of a project cash flow leading to different NPV and GT outcomes.

Choosing the appropriate bonding instrument may determine the viability of some projects;

primarily, marginal, and mature fields.

Preliminary results show that, under the proposed regime, total government participations

vary from approximately 34% to 38% of the total gross revenue, not including bond-related

expenditures. These GT values are calculated through the sum of participations within each

group (of governmental participations) divided by total gross revenue. If instead, NPV (with

discount rate of 15%) were calculated individually for each participation, summing up all

participations, and dividing by total field production, GT values would represent approximately

181

65.9% (Equations 1 and 2). IfNPV were to be calculated with a discount rate of 0%, GT values

would represent approximately 55.7%. Results also indicate that among selected instrument

options, EIP allows better NPV performances, followed by LOC.

n

IVPL(k,w;) ]=1

TP where:

i =number of groups-? i = 1, ... ,5

n = total number of participations within each group

k = Discount Rate

w; i = /h participation within the i1h group

TP =Total Production

n

z:w;i j:;l

TGR where:

i =number of groups-? i = 1, ... ,5

n = total number of participations within each group

w; i = r participation within the i1" group

TGR =Total Gross Revenue

Equation (5.1)

Equation (5.2)

All instrument options affect government earnings on direct and indirect taxation.

Collateral account instruments (PCCA and LSCA) improve government earnings due to interest

revenues from escrow accounts. Options EIP and LOC allow deductions of premiums and fees,

significantly eroding government earnings.

Figure 6.5 compares direct and indirect government participations and other project

expenditures with total project gross revenue. The three most significant participations are:

Operational Costs (OpEx), Investment (CapEx), and Corporate Income Taxes (CIT),

respectively. When compared to other project participations, closure costs correspond to a very

small fraction of the total gross revenue.

182

" " .. " i! "' : e (!)

Net Profit LOC: 39.22%

PCCA: 39.74%

LSC A: 39.73%

E IP: 39.20: '%

Closure & Bond Expenditures

LOC: 0.83%

PCCAo 1.01 %

LSCA: 0.98%

EIP: 0.78%

OpEx 12.21%

GT LO C: 36.21%

P CC A: 36.49 %

LS CA: 38.49%

t: II"': :.:U::L:l:.::l:%

Figure 6.5. Total participations agaiost total gross revenue (lOO%) for Field C (l-18 MMbbl). Government participation in this project (GD constituted. on awrage. 36.36%. not including bond-related earnings. EIP allows the highest payoff for this prQject.

Figure 6.6 compares some of Field C cash flow results obtained in the simulations of all

four instrument options. The choice of Field C (148 MMbbl) for this comparative representation

has to do with its economics. The other projects do not reach the minimum requirement to allow

the collection of PE compensations. Instrument choice does not affect financial expenditures

(11.54%) or operational cost (12.21%). Option LOC (36.21%) allows the lowest GT

participation, followed by options EIP (36.23%), and PCCA and LSCA (36.49%).

Instrument choice affects bond expenditure values as follows: option EIP (0.78%) allows

the lowest value, followed by option LOC (0.83%). Low expenditure is due to the payment of

annual premiums (around 3% of the total bond requirement) in contrast to the full bond amount

required for options PCCA and LSCA. During development and production phases, premiums

183

can be deducted from CIT. This implies that bonding costs are being shared between industry

and government. The small difference between options PCCA (1.01%) and LSCA (0.98%)

occurs because option LSCA allows the spreading of bond payments throughout a four-year

period, and option PCCA requires the full payment at startup. Since interest earnings from

escrow accounts are taxed as ordinary revenue, during the first four years option PCCA generates

more taxable revenues than option LSCA. Consequently, GT values from option PCCA are a

little higher than GT values for option LSCA.

Sensitivity analyses indicates that instrument option PCCA performs better than option

LSCA on small and medium size projects (up to approximately 53-60 MMbbl). According to

this model, option LSCA begins to perform better than option PCCA in projects larger than 60

MMbbl. There following aspects may explain this behavior:

• Interest earnings from the money allocated in escrow accounts are not taxed until

project net cash flow becomes positive. Since option PCCA allocates more immediate

capital than option LSCA, option PCCA allows higher interest earnings, reaching positive

net cash flow before option LSCA.

• This model was not designed to take into consideration opportunity costs. A future

project should include parameters such as cost of startup money and opportunity costs.

Intuitively, it seems obvious that projects allowing the spreading of bond payments over a

period of four years would provide better payoffs than projects requiring upfront bond

payment.

• Closure costs were stipulated based on a percent of project's gross revenue. In

projects larger than 60 MMbbl, high closure costs generate high bond requirements, and,

at this point, interest revenues earned during the first four years under option PCCA cease

to generate the customary NPV advantages obtained in smaller projects. For larger

projects, the negative impact of substantial upfront cash disbursement surpasses the earlier

advantageous scenario.

Figure 6.6 shows plots of sensitivity analysis of NPV values against closure costs for

Fields A, B and C. Each graph demonstrates five different scenarios corresponding to one of the

five instrument options (PCCA, LSCA, EIP, LOC, and, "Nobond", as a base case).

184

The most conspicuous impacts within this study can be found on Field A simulations.

This is due to the size of the reservoir, only 9 MMbbl. Simulations under a "No Bond" scenario

allow NPV values varying from 1.01 to 0.51 MMUS$. For option PCCA, NPV varies between

0.91 and- 4.77 MMUS$, and GT varies between 9.59 and 13.71 MMUS$. Option LSCA allows

NPV varying between 0.90 and - 5.82 MMUS$, and GT between 9.58 and 11.07 MMUS$.

Option LOC allows NPV varying between 0.92 and -1.25 MMUS$, and GT between 9.56 and

6.94 MMUS$. Option EIP allows NPV varying between 0.92 and -1.01 MMUS$, and GT

between 9.56 and 7.31 MMUS$.

fustrument option EIP causes the lowest impact on NPV outputs, followed by option

LOC. Here, NPV declines and approaches zero as closure cost increases toward MMUS$ 50.

Option LSCA performs better than option PCCA. For these plots, NPV becomes negative when

closure cost approaches MMUS$ 15. Field A becomes unfeasible at lower closure cost values

when compared to the other field simulations. Once again, this is due to the size of the project,

which is considered merely marginal.

For all instrument options in Field B simulations, NPV values do not reach zero until

closure cost exceeds MMUS$ 100. fu this case, option EIP allows the most favorable scenario,

followed by option LOC. Curve slopes indicate that instrument options LSCA and PCCA

significantly impact NPV outputs as closure cost increases.

Plots for Field C simulations indicate a slope inversion in options PCCA and LSCA,

where option PCCA begins to perform better than option LSCA. This inversion occurs in

projects involving reserves between 53 and 60 MMbbl. This behavior continues unaltered for all

larger fields. The two main reasons for this shifting are:

• For options PCCA and LSCA, all interest earnings are annually withdrawn from the

collateral accounts and handed over to the lessee. Tax rates upon interest earnings for

these instrument options are the same. For smaller fields (less than 53 MMbbl)

instrument option PCCA earns more interest revenues than option LSCA. Therefore, in

medium (up to 60 MMbbl), smaller, and, primarily, marginal projects, interest earnings

received during the project considerably enhance project cash flow performance. fu

addition, under this scenario, the upfront bond payment required by option PCCA seems

not to impact significantly NPV performances.

185

• ln fields larger than 60 MMbbl, upfront payment of costlier bond requirements

becomes a substantial burden on cash flow of projects using instrument option PCCA.

The impact remains considerable even taking into account interest earnings during the

entire life of the project. Therefore, option LSCA performs a little better than option

PCCA, especially in large projects where the possibility of spreading bond payments

throughout a period of four years does become a key factor.

lnstrument options EIP and LOC allow superior NPV performances in all projects, but

especially on projects requiring higher closure costs. Small projects tend to be severely affected

by bonding requirements, regardless instrument choice. lnstrument options that require

allocation of large amounts of cash at the startup inflict high opportunity costs. Regulators

should recognize this condition offering flexibilities and alternative bonding instruments.

Regulators should also consider some form of tsx incentive in order to extend the life of

some small and marginal projects (SCHIOZER, 2002). Due to high operating costs, large

companies may not have interest in some of these projects. However, small contractors may

recover oil in the same projects at lower operating costs with attractive profit margins. lncentives

may reduce direct government earnings, however small and marginal fields will have their lives

extended, levering investments and improving competitiveness within the sector.

Figure 6. 7 shows sensitivity analysis results under the government perspective (plots of

GT against closure costs). For all field simulations, instrument options PCCA and LSCA show a

pattern of linear growth for GT. lnstrument options EIP and LOC present a trend of linear

decline for GT as closure cost increases.

For Field A simulations, option LSCA draws attention to its steep GT increase as closure

cost also increases. Option PCCA also displays GT improvement as closure cost increases,

though with less intensity than observed in option LSCA.

When options EIP and LOC are compared against the base-case option "Nobond", both

instruments show a declining trend as closure cost increases. This occurs because it is possible to

deduct premium and fees from CIT. Obviously, the main objective of bond requirements is not

enhancing government revenues, however, for comparison purposes, option LOC allows lower

GTvalues.

186

80

300 J i

0

FIELDB

20

20

40 60 Closure Costs (MMUS$)

·· .

40 60 Closure COsts (MMUS$)

Leasing Specific

Pre- Paid

Ex- Post Insurance

No Bond

80 ,00

.. * .*

80 ")()

Figure 6.6. NPV vs. Closure Costs. Behavior of Net Present Values against closure costs. Sensitivity analysis from simulations in Fields A, B, and C.

187

Field B simulations show similar behavior. Because of taxable interest earnings over the

entire life of the project, option PCCA accrue more GT than option LSCA. Option LSCA allows

the spreading of bond payment during the first four years, accruing comparatively less GT.

Field C simulations involve much larger projects; consequently, instrument options PCCA

and LSCA display a very similar behavior. The difference generated because of the spreading of

bond payments becomes less significant in projects of such dimensions. As expected, options

LSCA and PCCA allow significantly higher GT, and options EIP and LOC, for allowing the

deduction of premiums and fees, result in lower GT.

Figure 6. 7 indicates that under a "No bond" regime, GT for the performed simulations do

not vary even upon closure cost increases. Obviously, this observation is only valid for direct

government earnings. Indirect government participations would involve items such as corporate

income tax for third parties performing closure operations and income tax from workers involved

in the process. This would lead to higher GT, as closure costs were to increase.

Some agencies do not accept insurance policy instruments. They claim insurance

products merely transfer liability from lessees to insurance companies, not providing a factual

performance guarantee. On the other hand, insurance companies tend to be very dynamic and

creative, and new insurance products are often developed to satisfy more strict bonding rules.

Letters of credit are under similar opposition from regulators. Some agencies argue that a LOC is

only as good as the issuing institution. If the issuer becomes insolvent, the guarantee becomes

void.

Sensitivity analyses were performed in order to verify whether oil price changes create a

more favorable scenario for a specific bond instrument. Results confirm that there is a

proportional and linear growth pattern for all field simulations involving all bond options.

Changes in oil price may be of great importance for deciding project feasibility, but not for

determining what is the most appropriate bond option.

6.6. CONCLUSIONS

The choice of bonding instrument is an important aspect of the decision making process

and may determine the feasibility of small and marginal projects. Small projects usually imply

limited profit margin that can be severely undermined by inapt decision-making.

188

The Petrobond algorithm provides useful flexibility for estimating economic impacts of

bonding instruments under government and industry perspectives. Option PCCA generates

significant impacts on all project simulations. Evidently, cash disbursement in such a manner is

not an efficient way to finance long-term closure operations with high costs.

For all simulations, option EIP offered better cash flow performances. Option LOC was

rated second best in all field simulations. Nevertheless, all simulations were performed under the

assumption that operating companies own top credit rating. This assumption permitted

collaterals to be waived and allowed generous premium rates. Future research is needed in order

to investigate the performance of LOC instruments under less favorable scenarios. The

sensitivity of other components should also be further investigated in future studies.

All simulations involving options PCCA and LSCA show that GT increases along with

closure costs, as NPV declines. Options PCCA and LSCA combine significant negative impacts:

worse project profitability and higher government take. In order to make these collateral account

instruments more competitive with options EIP and LOC, tax incentives would have to be

provided. However, it is very unlike that any form of tax incentive would surpass the benefits

offered by option EIP, for instance.

Even though much criticism is directed to ex -post insurance policy tools, such as option

EIP, some insurance products may provide mechanisms to award lessees with good fmancial and

environmental records; thus, a motivation for companies to pursue similar records.

Proportionally, taxes, levies, and other governmental participations can affect more

severely small, marginal, and mature projects. Additional research should be conducted on the

impacts of incentives and relief mechanisms on small, marginal, and mature oil fields. This

future study would be an effort to extend the life of mature fields and, concomitantly, engineering

a viable and sound bonding system for small and marginal fields.

Some indirect effects of bonding requirements may be very appealing. For instance, in

order to reduce bond requirements, companies are motivated to fmd ways of demonstrating to

authorities that closure costs can be less than previously estimated. For instance, intensification

of investments on research can lead to technological innovations that may reduce closure costs,

and, consequently, bond requirements.

The results obtained in this study are primarily useful for overall strategic evaluations.

Results may also provide guidelines for determining other potential impacts caused by other

190

bonding instruments. Decision-makers may use this study to develop general strategies for

projects under bonding regimes. Authorities may use tbe study to determine whether a current or

proposed bonding regime provides the necessary protection without discouraging investments.

Finally, the proposed model may help in tbe determination of tbe approximate financial burden

caused by different bonding instruments on different petroleum projects.

II. REFEREED ARTICLE III- Resources Policy, published in 2001

TITLE: IDENTIFYING POTENTIAL IMPACTS OF BONDING INSTRUMENTS ON

OFFSHORE OIL PROJECTS

AUTHORS: Doneivan F. Ferreira<*l, Saul B. Suslick<*l

(*)Department of Mineral Resources Policy and Management, Institute of Geosciences, State

University ofCampinas/UNICAMP, P.O. Box 6152, Campinas, SP 13083-970, Brazil

ABSTRACT

The present paper deals witb the potential financial impacts of different bonding instruments on

offshore oil projects. Three types of performance bond instruments (corporate surety, leasing

specific abandonment account, and cash) were tested and analyzed for three offshore oil

producing fields under a hypothetical bonding regime. Sensitivity analysis of "net present" and

"government take" values indicates corporate surety bonds cause fewer impacts yielding

significantly better payoffs. Several related issues are discussed considering government and

industry perspectives.

Keywords: bonding policies; decommissioning; bond instrument options

6.7. INTRODUCTION

Due to increasingly stringent policy requirements and higher operating costs, offshore

decommissioning has the potential to become one of the major issues facing the global petroleum

191

industry in the near future. Several regulatory approaches can be adopted to guarantee that

companies and operators will meet all decommissioning obligations, safeguarding government

and taxpayers from noncompliance costs (environmental and financial liabilities). This study

focuses specifically on the application of the bonding system, an incentive approach for

environmental policy.

Most bonding regimes allow companies to use a variety of bonding instruments.

Petroleum companies generally prefer surety bonds since, as this bonding arrangement typically

allows significantly better payoffs to a company, as this paper will suggest. Additional options

are provided mainly to give flexibility to companies that fail to qualify on the difficult surety

bond underwriting process. Even though the superiority of surety bonds may be incontestable,

impacts caused by different bonding instruments should be assessed and compared. This paper

is a first step in addressing the impact of currently available bonding instruments.

The authors recognize there are other essential economic issues regarding the

decommissioning of offshore installations that are not considered in the present study (e.g.,

optimum decommissioning startup, single or phased decommissioning approaches, technical

decommissioning options, and technological innovations). This paper is divided into four

sections. The first section briefly describes current decommissioning obligations in the offshore

oil and gas industry. The second section offers a concise overview of existing regulatory

approaches and a detailed explanation of actual bonding regimes and available instruments. The

third section presents a financial evaluation model for three bond options. This model is based

on a series of discounted cash flow and sensitivity analyses for three distinct offshore oil

producing fields. The final section discusses some of the regulatory issues involving the

application of bonding mechanisms and its financial impact from both government and company

perspectives.

6.8. OFFSHORE INDUSTRY AND DECOMMISSIONING

There is no agreement on an exact figure, but it is safe to say that there are over 7,270

offshore oil and gas installations in place around the world today. These installations are

distributed over more than 53 countries worldwide (PM'E and HENDARJO, 1998; ODCP, 1998;

POREMSKI, 1998; GRIFFIN, 1998a; PROGNOS, 1997). Offshore installations are usually

planned for 20-year projects, but most platforms can have a functional life ranging from 30 to 40

192

years. At the end of this period, as recoverable reserves are depleted, unless platforms are reused

or relocated, they must be decommissioned. This process involves several stages including

closing, plugging and abandoning wells and pipelines; cleaning and making facilities and

structural components safe; removing some or all of units and facilities; disposing, reusing or

recycling them; clearing sites; and providing monitoring and surveillance where required

(FERREIRA and SUSLICK, 2000).

Many aging offshore fields around the world are near the end of their productive lives,

and many others have already economically depleted their resources. Consequently, between

now and 2025 it should be expected that over 6,500 installations will be decommissioned at an

estimated cost of US$ 20-40 billion (COLEMAN, 1998). During the past five years there has

been exhaustive discussion in the literature concerning decommissioning costs (UKOOA, 1995;

ROBINSON and IRELAND, 1995; ARNEY, 1996; GRIFFIN, 1996, 1998a; DELLA, 1997;

TW ACHTMAN, 1997; PROGNOS, 1997; MMS 1997b, 1999a; WATSON, 1998;

PRASTHOFER, 1998; PHILLIPS, 2000). Due to great uncertainties regarding regulatory trends

and acquired experience on the decommissioning of large platforms, cost estimates tend to vary

significantly. Nevertheless, decommissioning costs may represent up to 10% of the total

investment of an offshore project (BORGHlNl eta/., 1998).

6.9. THE BONDING SYSTEM

The main approaches to environmental policies are Command and Control (direct

regulation) and Economic Incentives Mechanisms (market alternatives). Both Command and

Control (CAC) and Economic Incentive Mechanisms (ElM) have been exhaustively discussed in

the literature, including their characteristics, applications, and efficiencies (BOHM, 1981;

STOLLERY, 1985; WEBBER and WEBBER, 1985; CONRAD, 1987; BAUMOL and OATES,

1988; PERRlNGS, 1989; COSTANZA and PERRlNGS, 1990; CORNWELL, 1997).

CORNWELL and COSTANZA (1994) compare CAC and ElM approaches, and some

aspects are here adapted to the offshore oil sector: The CAC approach consists of establishing

and enforcing laws and regulations, and of setting objectives, standards and technologies with

which agents must comply. The ElM approach involves providing economic incentives to

encourage desired behavior; it encourages the distribution of responsibilities among all

stakeholders, decentralizing the decision-making process to protect lease areas; and it relieson

193

performance objectives rather than on a pre-established course of action. Economic analysis

indicates that present methods of enviromnental protection, mostly based on CAC strategies, are

inefficient and often provide disincentives for directing resources toward abatement. The main

causes are: (I) great uncertainties in calculating end-of-leasing costs; (2) costly and lengthy

litigious processes; (3) homogeneous treatment of companies and operators (no record-based

assessment); (4) great information burden on the regulatory agency (selecting the best technology

and enforcing penalties for noncompliance); (5) little incentive for development of innovations

that can result in improvements and cost reductions; ( 6) incentives for regulatory evasion rather

than regulatory compliance; and (7) vague regulatory language allowing companies to build

persuasive cases by showing that requirements are unachievable.

The bonding system, also know as financial assurance system, is one of the EIMs

presently being applied in the oil sector. In a broader sense, bonds are financial instruments used

to provide legal guarantee of indemnity in case contracting parties fail to meet contractual

obligations. In the offshore sector, bonds indemnify authorities against failure to comply with

lease contractual obligations. They safeguard agencies against technical and financial failure,

premature or unplarmed decommissioning, and contingencies. The bonding system shifts the

financial risk from the potential victims (regulatory agency and taxpayers) to the oil companies or

operators by internalizing potential costs. In case of default, funds necessary to complete all

decommissioning obligations would be promptly available, avoiding complicated legal processes.

Essentially, bonds are accessories to proposed contracts and they may be used several

times within a single contract. There are two major bond categories: (1) financial bond, a bond

that guarantees the payment of a specific amount determined by the bond in case a contractual

obligation is not met; and (2) perfonnance bond, a bond that guarantees the total completion cost

of a contractual obligation (JOHNSON, 1986; ROWE, 1987; CORNWELL, 1997; MILLER,

2000). Bonding instruments come in several forms with unique attributes and requirements:

some are the pledged assets of a company (cash, securities, real estate, escrow accounts, etc.);

others represent a guarantee for a company's performance or fulfillment of obligations (surety

bonds); still others are securities issued by bonding or insurance companies, banks or other

financial institutions; and some are instruments that indicate the deposit of cash (certificates of

deposit) or the existence of a line of credit (letters of credit) (BRYAN, 1998).

194

The bonding system used by the United States Minerals Management Service (MMS) for

the Gulf of Mexico is briefly described below as an example of a bonding regime currently in

place for the offshore sector (information based on the MMS- NTL 98-18N, 1998):

Companies acquiring oil and gas leases from the U.S. MMS post a preliminary financial

bond (general bond) guaranteeing financial aspects of the lease contract (regular payments of

rents and royalties, civil penalties, fines, etc.). A company holding more than one lease may opt

for an areawide bond (blanket bond). ln this case, a single areawide bond may cover multiple

leases. A lease may be subdivided into several aliquots. Companies wishing to explore, develop

projects, and produce hydrocarbon resources within a specific aliquot are required to post a bond

in advance (supplemental bond). This supplemental bond is equal to the best-cost estimate for

completing operations under the established lease contract. Therefore, before a company is

granted licenses or permits to drill, deepen, or alter wells, install platforms, or perform

modifications on existing installations, a supplemental performance bond must be posted to cover

all plugging and abandonment, decommissioning, and site clearance obligations. Either the

leaseholder or the designated operator may place the supplemental bond. Multiple supplemental

bonds may be found within a lease, but a single supplemental bond carmot be used to cover

multiple operations. At present in the Gulf of Mexico there are 390 active leases and 154

designated operators holding supplemental bonds (WILLIAMS, 2000). Decommissioning of

pipelines is covered by a different bond regulation40 (Pipeline Rights-of-Way).

General bonds must be maintained until the lease has been terminated or transferred.

Supplemental bonds must be maintained in effect and in good standing for the duration of the

project and until decommissioning obligations are met41 (or until a new party assumes

operations). If decommissioning activities are being conducted concomitantly during the life of

the project (phased approach), and if such activities are satisfactorily completed, authorities may

authorize proportional releases of the bond.

A bond may be subject to forfeiture for different reasons: (1) if a well or installation has

been abandoned or temporarily closed without initiating procedures; (2) if an operator fails to

meet decommissioning obligations in accordance with approved plan; or (3) if a company fails to

maintain the amount bonded.

"'A general bond must be posted before a pipeline is put in place (MMS- NTL 98-18N,l998). 41 Some restrictions apply.

195

Other countries have adopted, or are in the process of adopting, bonding mechanisms. The

UK government requires companies to provide security equal to at least I 00% of the expected

decommissioning costs of all installations and pipelines of proposed projects (DTI, 2000a). The

Brazilian Petroleum Agency (ANP) is in the process of offering bids for its first marginal fields.

The Agency is studying the possibility of establishing some form of bonding regime (BRAZIL

ENERGY, 1999).

6.10. FINANCIAL EVALUATION OF BONDING OPTIONS FOR THREE PRODUCING

OIL FIELDS

The objective in this section is to determine the effect of bonding regulations on offshore project

value. Three different bond instruments are used to determine the sensitivity of the variable

denominated "bond option". The study shows three offshore oil-producing projects (Fields A, B,

and C) in the Brazilian Outer Continental Shelf (OCS) with recovery reserves ranging from 50 to

500 MMboe (million of barrels of oil equivalent). All three projects are carried out under a

hypothetical bonding regime. Each scenario involves some convergence factor; in this case, it is

the bond option. Each field project is tested for all possible scenarios providing cash flow

simulations for all bond options. Each bond option yields different impacts on project

profitability, which are based on a discount cash flow analysis. This process identifies the least

impacted project.

The available options are indicated in Figure 6.8 and can be sununarized as follow: (1)

Cash Bond: the company is required to fund an escrow account in advance (before production

starts); (2) LSAA Bond: the company is required to completely fund a leasing-specific

abandonment escrow account within four years or by the beginning of the year in which the

agency projects that the company will have cumulatively produced 80 percent of the originally

recoverable reserves, whichever is earlier; and (3) Surety Bond: the company is required to obtain

a corporate surety bond which must cover the entire life of the project. Two additional scenarios

(benchmark scenarios) are provided as means of comparison: a "No Bond" scenario where

decommissioning requirements are enforced, but no financial assurance is required; and a "No

Decommissioning" scenario where no end-of-leasing obligations or bonds are required. The

company ceases production and leaves when the field is economically exhausted.

196

All options are evaluated on the basis of two economic criteria: the weighted Net Present

Value (NPV) per barrel discounted at 15%, and the total Government Take (GT) during the entire

life of the project. The following approaches are used to consider the results obtained in the

simulations: (1) the company's perspective: the preferable choice should have the highest payoff

(NPV); and (2) the government's perspective: the preferable choice should consider a reasonable

pattern of government earnings (GT) to maintain the regulatory role.

I Field A II F ie ld B II F ie ld c I

1 s "re ty 1 1 Cash I I LSAA I

8 on d In teres t

I

N e t Pro fit

Project E con om ic s

8 o n d R e quire m en t 1----------------8 on d P rem iu m --

Government Take

Abandonment & Decommissioning

1------------- __ a_ 2!J.d __ R_ •!~!! 1 .. T . ~----------------------------~ 0 ecom m issioning credit

deduction for future project

Figure 6.8. Hypothetical bond system. Note: Scheme showing three fields (A, B and C) and the three bond options available (surety, cash and LSAA). Surety bonds pay premiums, and cash and LSAA earn interest. Bond refund is available for cash and LSAA instruments after decommissioning obligations are satisfactorily met.

Some assumptions and simplifications are used to allow a better differentiation of

economic outcomes and a better way of comparing project profitability for each bond option.

The main assumptions are: (1) for all project simulations, "end-of-project" coincides with the

"end-of-production"; (2) the base-case cost for platform decommissioning is $15.0 million

(including costs to remove and dispose of all platforms within the field); (3) even after complying

with all bonding requirements, oil companies still must disburse out-of-pocket funds to pay for

197

decommissioning operations at the end of the project42; (4) bonds are released when

decommissioning operations have been satisfactorily completed (in the case of cash and LSAA

options, bonds are released and refunded); and (5) production starts at the first year for all

projects (since some tax categories depend on parameters such as production, this assumption

does affect govermnent earnings).

Under the present hypothetical regime, before a lease is granted operations must be

bonded in the following manner (Figure 6.9): (1) before exploration is permitted a General Bond

of $500,000 is required; (2) when the company applies for the development license, the

regulatory agency requires a detailed operation plan for development, production and

decommissioning activities, and sets a supplemental bond. The base-case used for all simulations

assumes that the cost for meeting all decommissioning obligations is equal to $15 million. The

Supplemental Bond is equal to decommissioning costs plus 15%, which covers third party profit

and overhead costs in case offorfeit (Table 6.4). Decommissioning costs are changed from $0 to

$150 million for each project to assess the financial impact of each bond option.

OFFSHORE 0 IL PROJECT

G eneraiBond Reqnirem ent (US$ 50 0 ,0 0 0 .0 0)

R is k A ssessm en t Survey

No Risk Spectrum R is k Low E .. H ig h . . . .

~ R k _________ j

No S u p p le m en t a I ~~ Supple m en t •

".!, •. Bond Value 't\i~ Bond required

Figure 6.9. Scheme showing the path for the establishment of the bond value (AEP, 1998a- MODIFIED).

42 Note that the bond was posted only as a financial guarantee, but the company still must pay for decommissioning operations.

198

The hypothetical fiscal regime used for the simulations is based on the current Brazilian

legislation, where the authors have firsthand experience. No capital expenditure is allowable

against corporate taxes; consequently, no bond disbursements can be deducted. Annual surety

premiums and fees are deductible since they are considered to be valid business expenses. The

rules for premium deductions vary significantly. Under this hypothetical fiscal regime, a rate of

40% of the total armual premium amount is allowed against corporate taxes. Decommissioning

costs can be treated as typical operation costs. In this case, however, decommissioning-related

expenditures take place during non-revenue years, and under such circumstances expenditures

carmot be deducted from corporate taxes. Companies may use the allowable deduction (under the

hypothetical scenario, 50% of decommissioning costs) as credit for future oil-producing projects.

For the present study, such deductions are not incorporated in the cash flows. Table 6.4 indicates

the main base-case parameters.

TABLE 6.4. PROJECT INFORMATION SUMMARY

Depth (meters)

Proj eel Life (years)

Recovered Oil Reserves (million bbl)

Total Operational Costs (million US$)

Total Investments (million US$)

Flat Oil Price (US$/bbl)

Decommissioning Costs (million US$)

General Bond (million US$)

Supplemental Bond (million US$)

Total Bond Required (million US$)

Deductible Rate for Surety Premiums

Deductible Rate for Decomm. Costs'

Field A

1000

312

53.6

348.8

248.7

Field-Specific Parameters

Field B

1000

16

148.9

995.3

377.4

Basic Parameters

20.00

15.00

0.50

17.25

17.75

40%

50%

Bond Annual Rates

Field C

1000

19

494.2

2662.3

1666.5

Taxable Rate Premium Deductible Rate Interest Earned (Interest earned) Rate (Premium paid)

Cash Bond

LSAABond

Sure Bond

5.50%

5.50%

1 Deduction amount can be credited to another project.

199

100%

100%

1.25% 40%

Government take (GT) is affected by variations in decommissioning costs (DC)

according to the application of different bond options. Changes in DC first affect supplemental

bond values (SPB) and then net revenue values (NR). Net revenue values directly affect GT

values. For this reason, NPV values are affected differently depending on the bond option

adopted and according to the changes in DC. Government Take includes the following taxes:

Royalties (ROY) (10% of gross revenue); corporate taxes (CT) (33% of net revenue); and special

government participation (SSP) when production exceeds 50,000 bbls/day. In the case of

projects adopting cash or LSAA bond options, Interest Earnings (BIE) from escrow accounts are

taxed as ordinary revenue. Government participation in the project is approximately 58%, not

including bond-related expenditures.

Figure 6.10 is a representation of the main costs and taxes applicable to the simulation

model.

GROSS REVENUE

TAXABLE REVENUE

I SSP I IBml cr

PROFIT GOVERNMENT TAKE

Figure 6.1 0. Graphic Representation of costs and taxes using the project simulation model.

Note: Capex ~Capital Expenditure (includes a straight line depreciation of all equipment and units over a ten-year period); BD ~Bond value (surety- amount is zero, either cash or LSAA -amount will be reimbursed at the end of the project); BFP ~ Bond Fees and Premiums (applicable only for surety); Opex ~ Operating Costs; DC ~ Decommissioning Costs. Roy~ Royalties (10%); SSP~ Special Government Participation (only applicable when production exceeds 50,000 bbl/day); BIE ~ Bond Interest Earnings (applicable only to cash and I bonds); CT ~ Corporate Tax (33%, it includes other government participation); BDR ~Bond Return (applicable only to cash and LSAA bonds). This scheme is for general visualization and does not indicate the correct proportions.

Three bond option scenarios are tested in the financial model. Each bond option is

described below:

• Surety Bond Option: A surety company writes a bond guaranteeing that a specific oil

company wil perform all required decommissioning operations; otherwise, the surety

company will pay the regulatory agency the amount bonded. In case of default, the agency

200

will request an independent contractor to perform the operations. ln some respects, surety

bonds are analogous to insurance policies in that companies pay annual premiums and fees to

keep bonds in place. Each surety company follows its own financial criteria to judge an oil

company and fix premium rates: net worth level, credit rating, decommissioning experience,

etc. Premiums are based on a percentage of the bond amount. For the simulations where

surety bonds are adopted, premiums of $12.50 per $1,000 per year (1.25%) are applied.

Premiums and fees are allowable against tax (deduction rate of 40%). The total amount to be

bonded is $17.75 million (DC plus 15% for third party profit and overhead costs) (Table 6.4).

The annual premium for this bond amount is $221,875.

• Cash Collateral Bond Option: Cash is placed in a federal insured bank account under an

escrow agreement between the oil company, the bank, and the regulatory agency. The escrow

agreement specifies that the agency has full control over the account until the bond is released

(after obligations are met). Escrow accounts pay annual interest (5.50%) which is available to

oil companies as it is earned. The annual interest for the established bond amount is

$976,250. Since interest is withdrawn annually, there is no accumulation of funds in the

escrow account. Consequently, interest earnings remain the same throughout the entire life of

the project. Companies cannot use the deposited collateral cash to fund decommissioning

activities. After the successful conclusion of all decommissioning-related operations, the

bond is released and the deposited amount is refunded. In case of default, funds are used by

the agency to contract an independent operator to complete all necessary decommissioning

obligations.

• Leasing-Specific Abandonment Account Option (LSAA Bond): For this trust agreement the oil

company must fully fund a lease-specific abandonment account within four years or by the

beginning of the year in which the agency projects the company will have cumulatively

produced 80% of the originally recoverable reserves, whichever is earlier. The initial

payment into the LSAA equals 50% of the required bond. Table 6.5 demonstrates the time

schedule for incremental payments of a LSAA bond (this example describes the situation on

Field A). The LSAA must be funded with $17.25 million (total supplemental bond amount)

and the initial payment is 50% of the required supplemental bond ($8.63 million). By the end

of year 4, even if the company does not produce 80% of the recoverable hydrocarbons

originally in place, the account must be funded with the full supplemental bond amount.

p

201 BLIOTECA

Cl

•

Interest earned is annually transferred to the oil company. After the conclusion of all

decommissioning operations, the bond is released and the deposited amount is refunded. In

case of default, funds are used to complete the necessary decommissioning obligations .

TABLE 6.5. MODEL FOR LSAA BOND ANNUAL PAYMENTS

Year Potential Recoverable Actual Recoverable $ Required at start Annual Payments

Reserves' (%) Reserves (%) of year (US$ million) (US$ million)

1 20.00 10.28 8.63 2.16 2 40.00 34.95 10.78 2.16 3 60.00 52.78 12.94 2.16 4 80.00 64.97 15.09 2.16

Total 17.25 Percent of recoverable hydrocarbons produced at the end of year as a % of recoverable

hydrocarbons originally in place.

As mentioned before, for benchmark comparison purposes, all project simulations include

two additional scenarios: (1) "No Bond" and (2) "No Decommissioning". In the "No Bond"

scenario the company is not expected to provide any anticipated funds to guarantee that

decommissioning obligations will be met. At the end of the project, during the first non

producing year, the company must pay for all decommissioning operations. The "No

Decommissioning" scenario is used to demonstrate the financial performance of a project where

no decommissioning or bonding is required. At the end of the project, the company walks away

without performing any decommissioning-related operation.

6.11. RESULTS

Effects on NPV values from Field A simulations are more significant than in larger

projects (Field B and C). In Field A, when the cash bond option is used, as decommissioning

costs increase beyond $90 million, NPV values become negative (Table 6.6).

Regardless the size of the field, LSAA bonds yield less significant impacts than cash

bonds. For simulations on Fields B and C, although maintaining a declining trend, NPV values

remain positive under decommissioning cost variations (from 0 to $150 million).

Surety bonds are the best option in all simulations, in that they yield higher NPV values.

Surety bonds are appealing tools mainly because they do not require upfront cash disbursement.

Eliminating upfront costs is a good strategy for improving project performance. In addition,

annual surety premiums and fees are allowable against corporate taxes. The level of deductibility

202

allowed is debatable and may vary from regime to regime. The deduction rate allowed during

simulations was 40%. In some cases, due to surety-related deductions, goverurnent earnings

(GT) decrease as decommissioning costs increased (Table 6.6).

TABLE 6.6. SENSITIVITY ANALYSIS FOR FIELDS A, BAND C, Al'ID BOND OPTIONS

FIELD A

DEC OM CASH LSAA SURETY (MMUS$) NPV GT NPV GT NPV GT

150 -0.80 5.12 -0.60 5.07 0.82 4.62 100 -0.07 4.94 0.06 4.91 1.01 4.63

75 0.30 4.85 0.40 4.83 1.10 4.63

50 0.66 4.78 0.73 4.77 1.20 4.64 25 1.02 4.71 1.05 4.71 1.29 4.64 10 1.24 4.67 1.25 4.67 1.35 4.65 0 1.38 4.65 1.38 4.65 1.38 4.65

FIELDB

DECOM CASH LSAA SURETY (MMUS$) NPV GT NPV GT NPV GT

150 1.72 5.60 1.79 5.59 2.39 5.25

100 1.98 5.49 2.03 5.48 2.43 5.26

75 2.12 5.44 2.15 5.43 2.45 5.27

50 2.25 5.39 2.27 5.38 2.47 5.27 25 2.38 5.33 2.39 5.33 2.49 5.28 10 2.46 5.30 2.46 5.30 2.51 5.28

0 2.51 5.28 2.51 5.28 2.51 5.28 FIELDC

DEC OM CASH LSAA SURETY (MMUS$) NPV GT NPV GT NPV GT

150 1.26 6.74 1.28 6.73 1.47 6.60

100 1.34 6.70 1.35 6.69 1.48 6.61

75 1.38 6.68 1.39 6.67 1.48 6.61

50 1.42 6.66 1.43 6.65 1.49 6.61

25 1.46 6.64 1.46 6.63 1.49 6.61

10 1.48 6.62 1.48 6.62 !.50 6.61 0 !.50 6.62 !.50 6.62 !.50 6.61

Note: The increasing cash and LSAA values, despite reduction in NPV values, are caused by the taxation of bond interest earned b~ such bond instnnnents. All values exEressed in US$/boe

For simulations using cash bonds, GT values increase as decommissioning costs rise and

NPV falls. The reason for this is that as DC increases, bond values also increase, providing

higher taxable interest earnings on escrow accounts.

LSAA is the second preferable bond option. The main difference between cash and

LSAA bonds is that cash bonds require immediate cash disbursement. On the other hand, LSAA

203

accounts can be funded in four years. For better comparison, interest rates for cash and LSAA

bonds are the same.

Considering all three bonding options, the cash bond option is least preferable. It impacts

projects negatively despite interest earned from escrow accounts. Cash disbursement in such a

manner is not an efficient way to finance long-term offshore operations with high

decommissioning costs. The same is true for LSAA bonds, but impacts are attenuated by time

allowance. The combination of "significant negative impacts on project profitability" and "high

government earnings" may provide a disincentive for investment flow within the offshore

industry. To make Cash and LSAA bonds more competitive with surety bonds, some tax

incentives would have to be provided. It seems though, it would be very unlikely that any form

of tax incentive would provide benefits comparable to the ones offered by surety bonds. Surety

bonds are a form of award for companies with good financial and environmental records, and an

incentive for new companies to pursue similar records.

Sensitivity analyses were performed in order to verify whether oil price changes create a

more favorable scenario for a specific bond instrument. The analyses verify that there is a

proportional and linear growth pattern for all fields and bond options. Changes in oil price may

be of great importance for deciding project feasibility, but not for deciding what is the most

appropriate bond option.

Table 6.7 presents an overall qualitative evaluation of the bond-option simulations.

Further studies are also needed to better assess cash flow financial performance under different

fiscal regimes. The results obtained in this study are primarily useful for overall strategic

evaluations. Results may also provide guidelines for determining other potential impacts caused

by bonding instruments. Decision-makers may use this study to develop general strategies for

projects under bonding regimes. Authorities may use the study to determine whether a current or

proposed bonding regime will provide protection without discouraging investments. Finally, the

proposed methodology may be used to determine the financial burden to be carried by the main

stakeholders (industry and government).

6.12. REGULATORY ISSUES AND BONDING SYSTEMS

Government officials provided the following answers when asked about the motivations

for establishing a bonding regime: (1) the government is very interested in achieving appropriate

204

decommissioning and addressing all environmental and safety issues; (2) there is no interest in

raising revenues through bonding mechanisms; (3) there is no interest in keeping bonds longer

than contractually established; and ( 4) the government is very interested in safeguarding

taxpayers from future liabilities43.

TABLE 6.7. QUALITATIVE EVALUATION OF BONDS USING THE SIMULATION MODEL Regulator's Perspective Industry's Perspective

Surety

Cash

LSAA

Level of Cost of Security for Regulatory Impact on GT Impact on NPV

Values' Values the Agency Compliance

***** • •' • ***** ••• • •• ***** ••• ** •• ****

NPV- Net Present Value; GT = Government Take.

Level of Difficulty for Instrument Acquisition

***** • **

***** = High; **** = High-Moderate; *** =Moderate; ** = ModeratewLow; * = Low (l) From Government's perspective; <'>Depends on allowable deductible rate (40% was assumed in the model).

In the oil sector, the main motivation is the concern over small parties acquiring small or

marginal production areas from larger companies (MMS, 2000a, 2000e; WILLIAMS, 2000; DTI,

2000b; ANP, 2000b). Without a financial assurance mechanism, large companies could open

small spurious companies to evade decommissioning liabilities.

Setting the appropriate bond requirement (amount) may be one of the greatest

predicaments within a bonding system. If bonds are set too low, the system may not provide the

desired incentive effect. On the other hand, setting bonds too high may discourage investments

in the sector. If authorities are primarily concerned with protecting environmental resources, then

all externalities must be addressed. If that is the case, the required bond must be high enough to

discourage projects involving great environmental risk and uncertainties.

Assessing the monetary value of potential environmental damages may be a problem. It

is not always possible to calculate the total monetary value of complex non-market goods such as

ecosystem functions and services, though many methodologies currently exist to calculate partial

values (COSTANZA, et al., 1997). In the past, due to inadequate bonding estimation, many

43 This question was addressed to bonding experts from the US Office of Surface Mining - OSM, US Bureau of Land Management - BLM, US Minerals Management Services - MMS, the UK Department of Trade Industry - DTI, and the Brazilian National Petroleum Agency- ANP (between 1999-200 I).

205

problems arose when mining companies became insolvent and the bond m place was not

sufficient to cover closure and rehabilitation costs (ALBERSWERTH, 1991).

To avoid liquidity constraints, most companies are encouraged to obtain surety bonds. As

mentioned before, these instruments do not require allocation of funds, only armual premiums

and fees. However, most small and newly formed companies may encounter some difficulty in

going through surety underwriting processes. For this reason, bonding instruments may appear to

work as market-restricting agents. As a remedy, most regimes offer alternative instruments. The

MMS currently offers two additional options as guarantee: ( 1) a trust agreement: a Leasing

Specific Abandonment Account (LSAA); and (2) US Treasury Notes. Usually, small companies

keep one of these two alternatives during approximately two years until they qualifY for the

surety bond underwriting process (MMS, 2000b). The UK government accepts cash, irrevocable

standby Letters of Credit, on-demand performance bonds, etc. (DTI, 2000a). Although a pool

bond alternative is accepted in other bonding systems, such an arrangement is not offered by the

U.S. MMS. The MMS argues that it is difficult to measure the potential risks of all companies in

a consortium, and consortiums tend to primarily benefit irresponsible parties. At present, for

Gulf operations the MMS holds approximately $900 million in surety bonds, $30 million in

Treasury Notes, and $10 million in trust agreements (LSAAs) (WILLIAMS, 2000).

Bonds may also appear to benefit large companies since requirements may be waived if

certain financial requirements are met (net worth44, assets, and projected revenue from other

fields and activities). The main concept is: low fmancial risk equals lower bonds. This waiving

process is sometimes referred to as financial capability or self-bonding. In the Gulf of Mexico

around 80% of the potential bonded operations are waived through such mechanisms

(WILLIAMS, 2000).

Costs to make some environmental policies work (monitoring and enforcement) may

become a great financial burden for agencies. Bonding mechanisms have been successful in

allowing lower regulatory compliance costs (MMS, 2000b). For instance, some monitoring

activities that could provide additional financial burden to the MMS are transferred to other

parties: (l) surety companies, which provide financial assessments for applicant companies

44 Some restrictions apply: plugging and abandonment costs cannot exceed 20% of a company's net worth.

206

(underwriting process), and closely monitor the financial health of their clients; and (2) the U.S.

Treasury Department, which monitors surety companies.

Another predicament within bonding regimes is tax treatment. In some countries, the

issue of charging taxpayers for decommissioning operations of private oil companies is being

severely questioned (PROGNOS, 1997). However, most regimes do provide a legal basis for

dividing the costs of meeting end-of-leasing obligations between the public and the industry. For

most tax regimes, decommissioning obligations are ordinary and necessary expenses. In general,

decommissioning expenditures are tax-deductible only when services have been performed and

payments have been made. The same rule applies when progressive decommissioning (the

phased approach) is adopted. Under some regimes, deductions are not allowed for

decommissioning activities carried out during non-income years (when production has ceased).

In this case, companies are allowed to carry a "credit" towards a future project, as is the case in

the current Brazilian fiscal regime (ANP, 2000b).

Tax deduction rates vary significantly from country to country. Deduction rates for

decommissioning expenditures in the UK range from 50% to 70% (PROGNOS, 1997). In

Norway, the government undertakes a great percentage of platform removal and disposal costs.

Companies cannot deduct such expenses in their corporate income tax45 (it does not include other

end-of-leasing activities such as well plugging and abandonment, site clearance, etc.). Therefore,

platform removal and disposal costs are not subjected to ordinary tax handling; they are kept

outside the Norwegian tax system. All other end-of-leasing costs are deductible as ordinary

operation costs (NPD, 1993 and NPD, 1999).

Under most fmancial assurance regimes, there is no deduction available for companies

depositing funds into escrow accounts (pledged to the government) until the company loses

ownership of funds. However, if a company pays fees or premiums to keep surety bonds or

environmental insurance policies, expenditures would be amortized over the time period covered

by the bond. The basic rule is that only an ordinary and necessary business expense is

deductible; capital expenditure is not. Being contractually liable for decommissioning operations

and emitting bonds (in anticipation) to guarantee such operations, does not entitle companies to

deduct cost of services before they are actually performed.

45 Government covers removal and disposal costs depending on corporate tax rates being paid at the time of decommissioning.

207

6.13. CONCLUSIONS

The application of bonding policies in the oil sector faces several obstacles. There are

different competing interests from several stakeholders, including oil companies, governments,

environmental interest groups, and other users of the sea. For this reason, solutions should share

the support of all stakeholders.

Simulations performed in this study indicate that further research on bonding instruments

is still needed to identify impacts, measure sensitivity of components, and improve the NPV

performance of offshore oil projects under bond regimes. Special attention should be given to

fiscal planning.

This study concludes that the most favorable bonding instrument under the given

circumstances is the surety bond. Surety bonds significantly attenuate impacts on such projects;

however, applicant companies must provide good fmancial and regulatory compliance records.

Bonding policies affect government earnings more significantly in small projects; therefore,

additional research should be conducted focusing on small and marginal fields.

Tbe impact on GT values is usually slightly negative with the application of corporate

surety bonds. For cash bond simulations in medium and large fields, GT values remain mostly

unchanged, indicating only minor reductions over significant decommissioning cost variations (0

to $150 million).

Under the bonding system, a company concerned with its image and corporate record is

motivated to comply with all decommissioning obligations (good records allow lower bonds and

premiums). In addition, to reduce effects on project profitability, companies are motivated to

fmd ways of demonstrating to authorities that decommissioning costs can be less than previously

estimated. For instance, investment in research may lead to technological innovations that may

reduce decommissioning costs and bond requirements.

208

CHAPTER VII- CONCLUSIONS

According to the information provided on Chapter II and III, the following answers can

be given to the questions asked in the introductory parts:

Question 1: How to guarantee that oil and gas leasing areas will be returned in similar

preexisting environmental conditions?

Answer 1: The establishment of comprehensive ex-post requirements, which must include well

plugging and abandonment, decommissioning of offihore installations, and clearing the area of

all obstructions.

Question 2: How to ensure that all ex-post obligations will be satisfactorily met, safeguarding

public economic interests by maintaining investments in the sector and, at the same time,

providing guarantees against negligent lessees and eventual economic and natural

contingencies?

Answer 2: The establishment of a performance bond regime.

Question 3: How to make such regime viable?

Answer 3: Make available a portfolio of bonding instruments, providing adequate flexibility for

accommodating the needs of dijJerent companies, but at same time, not eliminating incentives for

compliance; requiring the approval of an ex-post operation plan before operations begin.

Question 4: How to anticipate and attenuate the financial impacts caused by each of the dijJerent

forms of performance bonds required as financial guarantee for the completion of ex-post

obligations?

Answer 4: Design a decision tool to assist in the financial planning of offihore oil and gas

projects, simulating possible scenarios, giving the choice of dijferent bonding instruments, and

assessing their respective impacts on the profitability of offihore projects.

The marn contributions provided in the present thesis were: (1) A classification for

different forms of environmental damages in the upstream petroleum sector (accidental,

continuous, and ex-post damages); (2) The definition between financial bonds and performance

bonds; (3) A comprehensive assessment of currently available financial instruments used as

bonding tools; (4) A systematic classification for bonding instruments; (5) A series of modeling

209

exercises with the modeling tool STELLA®; and (6) A decision toll for managing offshore oil

projects under bonding regimes (Petrobond).

In the upstream oil sector, bonds are aimed at indemnifying authorities against costs

related to noncompliance of ex-post environmental obligations. An ideal bonding regime shifts

the fmancial risk from the agency to the lessees, forcing companies to internalize ex-post

damages and no compliance costs, motivating lessees to monitor the consequences of their

decisions. In case of noncompliance, funds necessary to complete all ex -post obligations would

be promptly available to regulators. Though a hybrid of market mechanisms and command and

control regulations, bonds are likely to achieve noncompliance protection objectives far more

cost efficiently than non-market regulations. Figure 7.1 illustrates the summary of risks offered

to the regulatory agency in case of noncompliance.

Bonds were found to be best suited to cover ex-post environmental damages. The main

factors include cost assessment and duration of mitigating operations. Some complications are

expected in the near future as emerging ex-post issues are further considered.

Since international legal provisions cannot specifY ex -post procedures for internal waters,

territorial seas, etc., guidelines and conventions can only be recommendatory in nature, and the

nation is sovereign in regulating and enforcing their offshore oil projects. For this reason, local

agencies or legislators should work on establishing requirements that may satisfY domestic and

international environmental demands and are economically feasible. Solutions must take into

consideration technical, environmental, and economic parameters, avoiding unfounded and

ineffective restrictive policies that can affect the continuation of long-term investment

commitments in the sector. Regulatory costs must be carefully examined. Figure 7.2 shows a

sununary of most significant regulatory cost producing aspects.

Compliance with all international, regional, and domestic policies might not necessarily

satisfY the expectations of public and interest groups. When oil companies are pressured by

public opinion, they will be compelled to surpass current regulations and even scientific

recommendations, despite significant economic impacts. To avoid this scenario, an open and

transparent dialogue with all stakeholders and an efficient flow of information with the Media is

highly recommended.

210

('''''' ... , ~6RM.i\Nee80ND' ..

I ENVIRONMENTAL LIABILITY

I RISK

Technically unqualified companies, \ Insolvency risk" ~ ' \

Risk of noncompliance with '\. '>,. \

\ performance responsibilities 7 7 Negligence risk \ Spurious business \

\ / RISK TO THE

REGULATORY /

Special Partici~~ \ AGENCY

Royalty payment~ (PE)

Risk of noncompliance with financial "\. "")& / responsibilities and deadli0 7 7 7

Rental Fees i

/ Tax payrnenf

Payment of penalties for noncompliance with I financial responsibilities

I FINANCIAL LIABILITY !

I I RISK

"- V .. .... ~~.~ ... '\. \ /

Figure 7.1. Summary of risks to regulatory agencies within bonding systems.

Available Technology and Techniques

Financial Institution issuing the bond Financial institution trying to exonerate

themselves from paying the bond

Figure 7.2. Summary of regulatory cost producing agents.

211

Communities pressing for more realist bonds

Partial removals cover a great range of different alternatives and combinations, and, if this

option were viable, it would represent cumulative savings ranging between 8% and 39%,

depending on variants, as it was demonstrated in the North Sea province. The main argument

used by interest groups to call for a ban on partial removal is the potential environmental impact

generated by partial decommissioning. However, the adoption of high cost solutions offers only

marginal or debatable environmental benefits.

Another advisable option for some, not all, environmental settings are artificial reefs,

which not only improve ecosystems services but also create new business opportunities. Another

interesting aspect of environmental issues is that the fishing industry has greater disturbing

effects on biodiversity than the offshore petroleum industry.

Technology leaps may offer, in the near future, profound impact on developments.

Minimal facilities and platformless development may become tomorrow's main option, reducing

both cost and implementation, and reducing decommissioning costs. It is also noticeable the

number of innovative offshore removal technology becoming available since 1995, most of them

in GOM and Norway. Incentives should be provided to ensure ever-improving technologies,

addressing needs and aspirations of all stakeholders, and, mainly, ensuring that the industry is

able to comply with all ex-post obligations.

Since decommissioning is unavoidable, ex-post planning must begin in early stages of

project preparation. The 5 R's approach should be considered: reduction, reengineering,

reutilization, rigs-to-reef programs, and then recycling, in this specific order. The best strategy is

planning, rendering offshore installations long and productive lives, allowing a high facility

utilization and delaying decommissioning costs as long as possible. Decommissioning several

fields at same time or sharing equipment and expertise may also provide substantial savings.

Observations indicate that, among the bonding systems studied, the MMS has the most

efficient system. It is important to emphasize that the offshore oil sector presents different and

more favorable characteristics than the remaining agencies and the areas under their jurisdiction.

The MMS deals with a scenario where monetary values are usually greater than in other sectors

such as hardrock mining, onshore petroleum, and coal mining. Even dealing with greater

financial responsibilities, non-compliance risks are significantly lower. The hardrock branch of

the BLM seems to hold the most vulnerable bonding system followed by the onshore petroleum

branch of the same agency. The main problems include the absence of a true incentive for

212

compliance by either ignoring true ex-post costs, or by requiring fmancial bonds instead of

performance bonds. Excessive flexibility granted in the form of instruments may be also

increasing liability risks.

For the Brazilian scenario, both financial and performance bonds are suggested. All

phases of projects should be bonded with financial and performance requirements, except for the

bidding phase, which does not offer performance risks. In order to provide the industry with

adequate flexibility and the agency with necessary guarantee, four types of financial instruments

are proposed: surety bonds, letters of credit, collateral accounts, and insurance policies. These

instruments were chosen based on the criteria defined on Chapter IV. Surety bonds may pose a

problem, since this instrument category is not yet available in the Brazilian market. Models

presented on Chapter VI also confirm the choice ofthis portfolio of instruments.

Large and historical companies are not the targets of the proposed bonding system. Since

some of these companies tend to accmnulate several leases at the same time causing the

allocation of large amounts of capital that could be applied in other productive ventures, some

form of blanket-bond should be offered. Some well-defined criteria, including a very strict

underwriting process, could be establish to provide historical companies with the opportunity to

use some form of self-bonding mechanisms. Such flexibility would reduce opportunity costs for

large investors, corroborating to the maintenance of investments within the sector.

The implementation of financial assurance requirements, as any other process, demands a

learning period that affects all stakeholders. The petrolemn sector is very dynamic and the

leaning process will follow the same course. The search for deficiencies and, mainly, loopholes

should be continuous. Consequently, reviews and minor adjustments should be frequent

(approximately every two or three years).

The administrative organization of governments may generate some problems for the

implementation of bonding regulations. In order to implement a feasible and efficient regulation,

the regulatory agency must coordinate all functions attributed to other agencies or government

offices. This will allow a harmonic management. The establishment of a central database is also

critical.

For most tax reg~mes, ex-post environmental obligations, including decommissioning

costs, are ordinary and necessary expenses. In general, such expenditures are tax-deductible only

when services have been performed and payments have been made. In general, the rule for

213

deductibility is that the expense has to be an ordinary and necessary business expense and not a

capital expenditure. The fact that a company is contractually liable for ex-post expenditures or

provides anticipated funds to guarantee such obligations (bonds), does not entitle it to deduct the

cost of such services before they have in fact been performed.

Additional research should be conducted on the impacts of incentives and relief

mechanisms on marginal and mature oil fields. This future study would be an effort to extend the

life of mature fields and, concomitantly, engineering a viable and sound bonding system for these

fields.

The choice of bonding instrument is an important aspect of the decision making process

and may determine the feasibility of small and marginal projects. For this reason, the

applicability of bonding systems must consider ongoing projects and projects near the end of

their lives.

For all algorithm simulations performed on the Petro bond program, environmental

insurance policy options offered better cash flow performances. The next best results were

attained by LOCs. Nevertheless, all simulations were performed under the assumption that

operating companies own top credit rating. Future research is needed in order to investigate the

performance of rating-dependent instruments under less favorable scenarios. The sensitivity of

other components should also be further investigated in future studies. Even though much

criticism is directed to ex -post insurance policy tools, such as option EIP, some insurance

products may provide mechanisms to award lessees with good financial and environmental

records, creating a motivation for companies to pursue similar records. Simulations performed in

this study indicate that further research on bonding instruments is still needed to identify impacts,

measure sensitivity of components, and improve the NPV performance of offshore oil projects

under bond regimes. Special attention should be given to fiscal planning.

Simulations performed in the Stella model conclude that the most favorable bonding

instrument under the given circumstances is the surety bond. Surety bonds significantly

attenuated impacts on tested projects; however, applicant companies must provide good financial

and regulatory compliance records. Bonding policies affect government earnings more

significantly in small projects; therefore, additional research should be conducted focusing on

small and marginal fields. Impacts on GT values are usually slightly negative with the application

of corporate surety bonds. For cash bond simulations in medium and large fields, GT values

214

remain mostly unchanged, indicating only minor reductions over significant decommissioning

cost variations.

Under the bonding system, a company concerned with its image and corporate record is

motivated to comply with all decommissioning obligations (good records allow lower bonds and

premiums). In addition, to reduce effects on project profitability, companies are motivated to

find ways of demonstrating to authorities that ex -post costs can be less than previously estimated.

Results obtained in this study are primarily useful for overall strategic evaluations.

Results may also provide guidelines for determining other potential impacts caused by other

bonding instruments. Decision-makers may use this study to develop general strategies for

projects under bonding regimes. Authorities may use the study to determine whether a current or

proposed bonding regime provides the necessary protection without discouraging investments.

Finally, the proposed model may help in the determination of the approximate financial burden

caused by different bonding instruments on different petroleum projects.

The application of ex -post environmental obligations and bonding policies in the oil

sector faces several obstacles. There are different competing interests from several stakeholders,

including oil companies, governments, environmental interest groups, and other users of the sea.

For this reason, solutions should share the support of all stakeholders.

215

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A hazard assessment of sea-floor sediment pollution by discarded drilling muds. North Sea Oil

Decommissioning Programme. Online since: 1999. Available m:

<http://www.abdn.ac.uk/-che210/mjstud2.htrn>. Access in: Feb. 25, 1999.

UNEP AND E&P FORUM- UNITED NATIONS ENVIRONMENTAL PROGRAMME AND

EXPLORATION AND PRODUCTION FORUM. Environmental management in oil and gas

exploration and production: an overview of issues and management approaches. Study: France,


234

UNICAMP/CEPETRO - STATE UNIVERSITY OF CAMPINAS and CENTER FOR

PETROLEUM STUDIES. Financial incentive system: financial guarantee mechanisms aimed at

funding or ensuring the performance of environmental obligations for petroleum production and

exploration. Study: technical consulting project, contract ANP/FUNCAMP/CEPETRO No.

2.400, 2001.

UKOOA. The Auris report: an assessment of the environmental impacts of the decommissioning

options for the oil and gas installations in the UK north sea. Study: Ukooa Ltd.'s, 1995. [Internal

report].

YOUNG, M.D., GUNNINGHAM, N., ELIX, J., LAMBERT, J., HOWARD, B., GRABOSKY,

P. and MCCRONE, E. Reimbursing the future: an evaluation of motivational, voluntary, price

based, property-right, and regulatory incentives for the conservation of biodiversity. Prepared for

CSIRO Division of Wildlife and Ecology, the Australian Centre for Environmental Law, and

Community Solutions for the Australian Department of the Environment, Sport and Territories.

Biodiversity Series, Paper n.9. Online since 1996. Available m:

<http://www.ea.gov.aulbiodiversity/publications/series/paper9/index.html>. Access in: Jan. 15,

2001.

YOUNG, E., D. and MCMICHAEL, C., L. Impact of production-sharing terms on investment

community performance statistics. In: SPE ANNUAL TECHNICAL CONFERENCE AND

EXHIBITION, 1998, New Orleans, LA. Proceedings ... New Orleans: SPE 52017, 1998.

WAELDE, T., W. The current status of the international petroleum investment: regulating,

licensing, taxing and contracting. The Centre for Energy, Petroleum and Mineral Law and Policy.

University of Dundee, v. 1-5, July 1995. [Internal publication].

WALKER, M., 0. Decommissioning of offshore platforms - US Department of State. In: JOINT

WORKSHOP ON THE DECOMMISSIONING OF OFFSHORE OIL AND GAS PLATFORMS,

1998, Jakarta. Proceedings ... Jakarta: [presentation], 1998.

WATSON, T. Re-use and disposal considerations -Amoco Exploration Company. In: JOINT

WORKSHOP ON DECOMMISSIONING OF OFFSHORE OIL AND GAS PLATFORM, 1998,

Jakarta. Proceedings ... Jakarta: [presentation], 1998.

WEBBER, B. and WEBBER, D. Promoting economic incentives for environmental protection in

the surface mining control and reclamation act of 1977: an analysis of the design and

235

implementation of reclamation performance bonds. Natural Resources Journal, n. 25, p.390-

414, 1985.

WEBSTER, L. Issues Coordinator, Issues Management Branch, Land Reclamation Division,

Alberta Environmental Protection (AEP). Electronic publication. E-mail received by

<[email protected]> in 1999. [Personal reference].

WILLIAMS, C. Interview with Carrol S. Williams, MMS official, New Orleans, LA, 2000.


236

TABLE A.l. QUESTIONNAIRE SUBMITTED TO BOND SPECIALISTS, REGULATORS, AND INDUSTRY DECISION MAKERS. REGtrJ .. ATOWS PERSPECTIVE 1:.:; .......... }./ >./.':.•:·>;.·.··.······

jl 1 F ..... <> ff!~~i CHARACTERISTICS .5 .5 f ~~ H

~~ & ATTRIBUTES c

1'5 li 'C

j'& .j ,g tif] ~ s

i~ i:ll 1 oi --i 11

i 'S e MECHANISMS & INSTRUMENTS

co 'OQ

it r~ lJ 'Hi H u lt :hl §I .!ll o'!

;:', ; (',C'/; .

Credit Guaratttt'eS: Corporate Sutety Bonds

Certificates of OePOstt

n Cash Equivalent (Cashier's Check, Certified

I Check, Money Order, Cash Oep¢stt, Cash Bond\ Letters of Credtt Govenunent .. Jssued Treasury Securities (T-Notes, T-bonds, Depostt of Securttles,

I I Investment Grade Securities\ (·!Real Estate and other oiedae of assets Financial Reserve security Agreements

I i I (•)Salvage Cash Accounts

Is 8 Escrow Accountlil

j Paid·ltt Trust Funds (Cash Tmst Funds) Bank Acc{.)UJltj;l. (in tJ:ust) Tt'ltst Funds with Periodic Payments SttUtdby Trt1st Funds

.s E:\iemal Sit1king Ftmd<:~

~ Lines of Credit Bank Guarantee (unde1iaking)

~

~~ FU1:mcial Test<:~, Balance Sheet Tests, Covenants,

j Sell' Guarantee, Selt'..Ftmdiu.g through Fil:tancial Reserves Corporate Guarantees., Parent Comp.'Uty

~ GuarMtee, Third~party Guarantees :111 Set..t\sides Revenues !! Environtneiltallnsurance

~ ~'1 Finite !nsurMce Life Insurance ~ .. Ailnuities

Risk Spreading: Pool Bonds

Risk Spreading: Designated-Purpose State Funds

* Soft instruments

APPENDIX B- DECOMMISSIONING OF OFFSHORE INSTALLATIONS

TABLE B.l. NONEXCLUSIVE REUSE MATRIX SUGGESTION

C'~ WHO IS BEST '14-C AT HANDLING?

~0.<- fl) 0::: .s>v. w w 0

0::: 1- 1- ..JO::: 'b :::> ~ u <(W

~IS' li: 0::: ~ i=::!: 0 w zo IS'~ u. w ll. ~ 1- WI-

IS' ...1 > 0::: 0 z 1-f/) LIST CRITERIA I'~ w 0 0 0::: 0 0:::> v fl) u u DJ u ll.U

Water depth 50% X X X X X X Processing 50%

Reservoir site/quality 50%

Geographic location 50%

Scale of modification 50%

Cost of modification 50%

Age of technology 50%

Early production 50%

Reputation 50%

Government influence 50%

Geopolitics 50%

Project manager attitude 50%

Marine rates 50%

Corporate culture 50%

NGOs 50%

Willingness 50%

Covertures alignment 50% 18 factors were suggested, but there are many others. Suppose each crrtenon had a s1mple 50:50 chance of success. The overall chance of a perfect match would be about 0.0004%, or 1 in 26,200. Finding a perfect match for an installation is not an easy task (Tilling, 2001- modified).

/:::,. NEEDS CULTURE CHANGE • ATTITUDE DRIVEN

0 STUDY WILL DEFINE X YOU CANNOT DO ANYTHING ABOUT IT

Possibility of recommissioning: Who would be best handling each criterion (based on methodology by TILLING, 2001)

238

TABLE B.2. DECOMMISSIONING COST ESTIMATE FORM Activities Decommissioning Planning • Engineering analysis • Contracting • Operation plan elaboration

Partial Cost: Regulatory Conformity • Permits and licenses (for all activities) • Environmental consultancy • Cost involved in reaching regulatory adequacy

Partial Cost: Decommissioning Preparation Services and "Safeout" • Cleaning and disposal of residual hydrocarbon • Safety preparation • Dismantling and separation of modules and equipment • Structural Reinforcement

Partial Cost: Well Plugging aud Abandonment • Assessment of well condition (data collection) • Inspections • Elaborating a P&A plan (method) • Operations • Sale Price of Reusable or Recyclable items

Partial Cost: Conductor Removal • Assessing regulatory requirements and difficulty level • Severing • Pulling (requires rig) • Oftloading (requires platform crane) • Transportation and Disposal • Sale Price of Reusable or Recyclable items

Partial Cost: Mobilization and Demobilization • Planning (assessing the type ofHLV required and availability) • Contracting the HL V

Partial Cost: Platform and Structural Removal • Planning (Removal in one piece or large pieces, or reducing them to small pieces) • Dec kiT opside Removal (including contracting HL V and cargo barge) • Pile and explosive Severing services (cutting and lifting) • Platform/Structural Removal (including contracting HLV and cargo barge) • Sale Price of Reusable or Recyclable items

Partial Cost: Decommissioning Pipelines and Cables • Assessing regulatory requirements • Engineering Planning • Diver related services (surveying, cleaning, cutting, plugging, burying and removing) • Contingencies • Lift vessels • Sale Price of Reusable or Recyclable items

Partial Cost:

239

Estimate ($)

Transportation and Disposal • Assessing regulatory requirements • Cargo Barge Services • Deciding on disposal methods (refurbish and reuse, scrap and recycle, or landfills) • Revenue from reuse destination and recycling • Disposal costs (steel, cement, marine growth, mud, etc.)

Site Clearance and Verification • Pre-demolition side scan sonar survey • Post-demolition side scan sonar survey • ROY deployment • Diving spread • Trawl test program • Contingency

Miscellaneous Project Management and Inspection Contingencies TOTAL GROSS COST TOTAL SALE EARNINGS SALE% OF GROSS COST NET COST

240

Partial Cost:

Partial Cost:

APPENDIX C- PETROBOND VARIABLES

TABLE C.l. OPERATIONAL VARIABLES

Field-Specific Characteristics

a) Basin location of the basin b) Field name of the producing filed c) Oil Reserves total oil reserves in millions ofbarrel (MBBL) d) Gas Reserves total gas reserves in millions of barrel of oil equivalent (MBBL) e) Oil type type of the oil being produced in the field

General Characteristics a) Exploration Period b) Development Period c) Production Period d) Water Depth

Production

a) Given Production

• Gas Royalties

b) Simulated Production

• Production Peak • Declining Curve

• Gas/Oil Ratio • Time to Production

Peak

• Gas Royalties

• Peak Duration

Cost

a) Cost Input

b) Calculated Cost

Investment

a) Annual Investment

b) Calculated Investment

length of the exploration phase (years) length of the development phase (years) length of the production phase (years) depth (meters)

annual oil (MBBL) and gas (Mm3) production data is provided for the production

phase'

portion of gas production, which will be subjected to the established royalty rate (in%)

the software will simulate the production of the field based on information provided2

maximum production value declining rate for the oil production curve

Portion of gas in the oil production

time to reach production peak

portion of gas production, which will be subjected to the established royalty rate (in%) duration of the peak production

annual operation costs provided in MMUS$ (maximum of20 years)

costs may be calculated through an estimation of operational cost per barrel of oil equivalent adjusted by the inflation (inflation is provide in the input of financial parameters)

in this input option investments are divided into expenditures (MMUS$) during the exploration phase and well cost, which is depreciable and amortizable (MMUS$) during the first five years of the project

in this input option the total investment is calculated based on the value provided by barrel of oil equivalent. These values are divided into depreciable and nondepreciable according to the proportion provided. In addition, as in "Annual Investments", values are divided into five years.

1 Production is then converted in Mm3 in order to facilitate the calculation of special participation values (PE). 2 The decline model used was exponential according to the given rate provided by the user.

241

TABLE C.2. FINANCIAL VARIABLES

Royalties

CO FINS

PIS

CIT

BID

Depreciation

Amortization

Discount Rate

CSLL

Rent { Price

Oil Price

Gas Price

Inflation

Exchange Rate

royalty rate on gross income

social Contribution Tax rate on gross income

PIS rate on gross income

tax rate on taxable income

bidding bonus paid in year zero

portion ofthe investment allowed to be depreciated

portion on the investment allowed to be amortized

discount rate used by the lessee

CSLL rate on taxable income

amount paid by the occupation of the area during exploration, development and production phases. The value is calculated in R$ and then converted to US$ according to the money exchange rate input.

oil price is calculated based on the Brent price according to the respective conversion factors for each oil type. The values are adjusted for current inflation.

given in US$ per BBL

given in US$ per m3

annual rate if inflation

US$/R$ exchange rate

242

Figure C. I. Petrobond Computational Algorithm (Photo: courtesyofTWACHTMAN SNYDER& BYRD, INc.).

243

TABLE C.3. BOND RELATED VARIABLES

Instrument Options:

a) Bidding phase:

b) Exploration Phase:

c) Development & Production:

Letter of Credit: a) Financial Bond b) Rate/Fees

c) Discount rate

d) Performance bond

e) Closure cost

Insurance Policy:

a) Lessee classification

b) Financial Bond

c) Premium Rate

d) Risk Discount Rate

e) Performance Bond Amount

f) Closure costs

Paid-in Collateral Account: a) Financial Bond b) Performance Bond

c) Discount Rate

d) Interest Rate

e) Closure Costs

Cash

Periodic Payment Collateral Cash Account:

a) Financial Bond

b) Performance Bond

c) Closure Costs

d) Interest Rate

e) Discount Rate

(!)Financial Bond- Letter o Credit, pre-paid collateral account, Insurance policy; (2) Performance bond- Not available for this phase (I) Financial Bond- Letter o Credit, pre-paid collateral account, Insurance policy; (2) Performance Bond- Letter o Credit, pre-paid collateral account, Insurance policy. (I) Financial Bond - Letter o Credit, pre-paid collateral account, periodic payment collateral account, Insurance policy; (2) Performance Bond- Letter o Credit, pre-paid collateral account, periodic payment collateral account, Insurance policy.

fixed value in MMUS$ annual rate for maintaining the bond (around 2% of the total bond value) discount rate allowed based on risk offered. Based on the performance bond amount. required bond amount in MMUS$ total closure cost (estimation) in MMUS$. Input for exploration and development/production phases

classification according to the SERASA (Brazilian credit evaluation center -A, B, C and D). The premium rate will be established according to this classification. fmancial guarantee amount in MMUS$

annual rate based on the total performance bond requirement (from 1.25 to 3.00%, according to the lessee classification rating)

risk discount rate based on the risk offered by the lessee. The discount is on the performance bond amount.

bond value in MMUS$

total closure costs for exploration and development/production phases. Values in MMUS$.

fixed value in MMUS$. performance bond amount in MMUS$. discount rate based on the risk offered by the lessee. This discount rate will only impact the performance bond amount Annual interest rate on the total bond amount (usually around 5.5%). closure costs estimation for the exploration and development/production phases in MMUS$.

fixed value in MMUS$.

performance bond amount in MMUS$.

closure costs estimation for the exploration and development/production phases in MMUS$.

annual interest rate on the total bond amount (usually around 5.5%).

discount rate based on the risk offered by the lessee. This discount rate will only impact the performance bond amount.

244

APPENDIX D - STELLA MODELING TOOL: DECOMMISSIONING AND BONDING

SCENARIOS

Developing decision tolls, complex models, for managing oil project decisions involving

decommissioning and financial assurance mechanisms, provides a way to anticipate economic

impacts of the several bond alternatives.

Complex models are essential for managing oil projects. The use of economic models is

an innovative approach to deal with the business decision uncertainties involved in the oil sector.

This approach integrates multidisciplinary segments (policy, environmental, social, fiscaL etc.)

with economics dynamics, providing a way to anticipate the economic impacts of the manifold

alternatives. Figure D.l illustrates the Interface Level of the Decision Model descnbed m

Chapter 2, where the current choice of bonding instruments is investigated.

This tool considers ten different bonding instruments:

1. Corporate Surety Bonds 2. Paid-In Cash Collateral Bonds 3. Periodic-Payment cash Collateral Bonds 4. Letter of Credit Collateral Bonds 5. Self Bonds 6. Third-Party Bonds 7. Real Estate Collateral Bonds 8. Environmental Insurance Policy Bonds 9.Poo1Bonds 10. State Funds

Each instrument will cause different impacts on the industry and on regulators.

The main objective of this model is to systematize the decision..making process by ranking each impact-parameter according to its importance (to both industry and regulators).

Each parameter will be assigned a degree of importance (from 0.0 to 1.0} in such way that the sum of all panuneters will be equal to 1.0.

When the degree of importance of each parameter is defined, all instruments will be ranked (from 0.0 to 5.0) according to industry's and regulator's perspective.

BOND INSTRUMENT OPTIMIZATION MODEL

~ ·........

Figure D.l. Part of the conceptual introduction ofthe decision model designed in the Stella tool. This control panel is located at the interface level of the software.

245

The three following model exercises were designed using the software package STELLA®

(Structured Thinking Experimental Learning Laboratory with Animation) which was developed

by High Performance Inc. for the Windows™ and Macintosh® operating environments. The

STELLA® is a multi-level, hierarchical environment for constructing and interacting with models

(STELLA, 2001). The present modeling was designed using the STELLA Research version for

Windows™.

COR.l\TWELL M'D COSTANZA (1994) were the first to apply the STELLA® in a

dynamic, interactive simulation model intended to examine the pollution abatement systems. As

described by Cornwell and Costanza, models are a trade-off between realism, precision, and

generality.

D.L A DECISION MODEL FOR A PERFORMANCE BOND REGIME

The offshore oil industry, by its very nature, is exposed to hazardous events with very

large consequences (TOPE, 1999). The economic impacts of safety and environmental

regulations are enormous. A company must have a clear understanding how decisions are made,

systematizing the decision-making process, and providing an effective consultation and

communication tool.

It is evident that regulations will be the main factor, but engineering and good practice

will largely form the bases for the decision-making process. It will also include the use of

innovative technology, choosing the best decommissioning options, etc. Decisions will

sometimes involve higher costs, uncertainties and risk tradeoffs.

The aim of these models is to establish a framework that best reflects the context of the

decision being considered. This framework developed is intended to aid in financial management

decision-making process. Its structure can be modified and adapted to suit the scenario or

situation being considered and to reflect future changes in technology, practices, and values. The

use of such framework for decision support may make the decision making process more

consistent, but it will not necessarily lead to consistent decisions. The actual decisions will

depend on the values and perceptions of stakeholders, which will vary from stakeholder to

stakeholder, and company to company. Several steps can be shown in the Interface Level of the

Stella model as illustrated in Figure D.2. The user, the decision maker, is able to control all

variables of the project.

246

MO!JEUJPERATION PANNEL

Only one option may be on

i _ Project Scenario:

a. Onshore

ONSHORE

i OFFSHORE

' Figure D.2. Interface Level: Basic project parameters Input Window. Knobs are macros to activate commands. Illustration of Stella tools for user input of project type (onshore or offshore). The two meters above show total annual production and total government liability. Alarms go off if current production leads to negative NPV and if liabilities are high.

D.2. FORECASTING

The first approach in this appendix must be to relate the sciences of forecasting and

developing models. Analyzing patterns and circumstances of past events and activities,

examining the parameters involved in a specific scenario, identifYing direct and indirect

relationships among cause and effect, understanding the driving forces behind occurrences,

systematizing the decision making process, formalizing potential outcomes, what is likely or even

could happen in the future, are vital procedures considered whenever there is an important

decision to be made. One or several of the steps above may be used unconsciously during

common daily decisions. But in fact, the science that systematizes such procedures to improve

the decision-making process is called forecasting. The reasoning that generates the fimdaments

for forecasts can be described as modeling, which is the systematization of all reasoning taking

247

into consideration all parameters involved in the decision-making process. Even while not

always recognized as forecasting, whenever we make a decision on capital goods, we make some

assumption on the future value and costs (FERREIRA, 2002).

Numerical forecasts are not meant to produce the factual numerical outcome. The results

of such attempts are meant to be interpreted by specialists that will identify probable trends and

eventually predict scenarios that will correspond to actual events. If a model is properly designed

it will be adequate to point out in the direction that a decision needs to be made, even if the

predicted numerical outcome is accurate.

The science of forecasting and modeling, both having the objective of providing the decision

maker with a tool for systematize the decision-making process, is hardly an academic program,

but any corporation, government agency, or manager wishing to make successful decisions will

make use of such sciences. Figure D.3. shows the Mapping Level of the Decommissioning

Process Submodel.

Computers have been used to model several scenarios. The use of computers allow the

forecast of scenarios taking into account several parameters and allow a range of values that

provide the sensibility of the model and its output to realistic variations in the key parameters and

assumptions, or scenarios. Alternative views (or scenarios) on how the future may develop can

usually be attained by changing the values of the various parameters (FERREIRA, 2002).

Computers are used to build and run complex models. Computers also allow the incorporation

within the model, of many variables and relationship that can be easily modified. The other

advantage provided by computers is the possibility of using a great range of database to run

simulations of different scenarios. It can also integrate variables such as policies, historical data,

public response, political will, physical data, etc.

• Defining the issue/problem: What is the explicit purpose for the modeling effort? The

purpose of this effort is to develop an understanding of how different forms of bonds impact

the profitability of an offshore project, and then to use this understanding to generate practical

charts showing the best types of bonding instruments for different project scenarios - a tool

for helping in the decision making process.

• Developing a reference behavior pattern: in order to make the written statement of purpose

more operational, it will be translated into a Reference Behavior Pattern, a graph over time of

the variable which best characterizes or represents the phenomenon attempted to be

248

understood. Sometimes a good reference behavior pattern IS not available to guide the

investigation.

CLOSURE EXPEND1TUR_E

Engineering & P!ann!ng

Platform Preparation

Conductor Remov.a! We!! Piugglng & Abandonment

Closure Savings

OFFSHORE Ciosure Cost Estimate

Estimated Closure osts Platform & Structural Removal

Site Clearance & Verification

Mobilization & Demobi!lzatlon

CLOSURE SAV!NGS~~~'i:ation & Disposal CLOSURE TfiBLE

PERFORMANCE FACTOR%

CLOSUHE EXPENDiTURE CLOSURE EXPEtliD1TUREjipUAJ-1CE

!N CASE OF DEF.D-JJL T

CLOSURE EXPENDITURE

TOTAL CLOSURE EXPENDITURE

Closure Addition

CLOSURE ADJTiONAL COST FACTOR% Estimated C!osure Costs

Figure D.3. Map Level view of decommissioning submodel.

249

D.3. CASH FLOW STELLA SUBMODEL.

This Stella model guides the decision maker through several ex-post related reflections

including the use of three different bonding mechanisms (surety bonds, paid-in cash collateral

account and periodic payment cash collateral account). At the end, the model provides the user

with results in Dollar values, percentages, and BOE. Stella is certainly not the easiest way to

create a cash flow spreadsheet, however, it is an excellent didactic tool to demonstrate all the

possible changes in variables and parameters and their impact on project value.

D.4. BOND CHOICE MODEL.

This Stella model attempts to systematize the bond choice paradigm. Why the majority of

regulatory agencies choose the instruments they choose? In opting from certain instrument

regulators try to reach equilibrium. Due to public pressure, regulators must impose sound

bonding requirements; however, such requirements will generate some negative impacts on the

industry, which in turn, will call for flexibility. Regulators must respond, in order to keep the

market competitive and maintain the investment flow in the sector. Flexibility, usually, increase

the risk for the regulators. Some instruments will be very positive for the industry, but very

negative for the regulators. A balance must be obtained. This cycle is also illustrated in Figure

2.3.

The main objective of this model is to systematize the decision-making process by

ranking each impact-parameter according to its importance (to both industry and regulators).

Each parameter will be assigned a degree of importance (from 0.0 to 1.0) in such way that the

sum of all parameters will be equal to 1.0. When the degree of importance of each parameter is

defined, all instruments will be ranked (from 0.0 to 5.0) according to industry and regulator's

perspective. This is all demonstrated in Table 2.5.

D.S. OFFSHORE PLATFORM REMOVAL: ECOLOGICAL IMPACTS.

Some decommissioning activities are likely to have enormous benefits m terms of

preventing pollution, environmental degradation, and accidents. Removing offshore structures

also has important safety benefits. However, the presence of offshore structures does improve

ecosystem services.

250

hgestwn of Detrital C

EquWt>num I·Cco

'

•ExciHnge Facto!

1~02 111 lh0 li\181<:,1

Ingestion of Pl1otosy1Fishing Rq)ulUUons

•Cons Ingestion Rate

•ConsumBt Respir Rate

•Plant mortality rato

C Plolllb & Pllytoplanldon

Max 1\g per surface nre

Addltonal Growth surface

Platform

C02 in ll'le Air L:::,.

C02 in the air

Fuel Emissions •C02 Manalon data

cD

Platform Scenario L:::,.

Indirect Emir:;s;ios •Plat Com Rate

Direct Production Emissions

cD Decommissioning Scenario L:::,.

FisfHng Regulations

plat conmlic,sion

Total Dac Emissions

8k1 •Dec Cont Rate Dec Emissions Data

Figure D.4. Carbon Model, map level modeling. This model simulates ecosystems around offshore platforms. The four main stocks include Carbon Detrital, Ca C02, Carbon Consumer, and Carbon Plants and Phytoplankton. Submodel "Decommissioning Scenario" internalizes ecological impacts of decommissioning operati including C02 emissions (FERREIRA and BOUMANS, 2001).

Several issues rise regarding commercial fishing (i.e. exclusion areas, sanctuaries, etc.).

This theme has attracted a passionate discussion between the oil and fishery industry,

environmentalists, and several NGOs (MMS, 1997; SANCHIRICO, 2000). As mentioned

before, fishing has serious disturbing effects on biodiversity. Plowing the top layer of the soil

with heavy nets is very harmful to crabs, shrimps and starfish, favoring only certain worms on

which flatfish feed. Offshore platforms, according to the study, even have a beneficiary effect on

the ecosystem, because fishing within 500 meters of a platform is prohibited, a interdiction that is

very questioned by NGOs connected to the fishery industry. Figures D.4 and D.5 illustrates a

modeling exercise where life around a platform is measured by carbon amounts. Although just a

modeling exercise, the output in Figure D.5 gives an idea of the ecosystem services improvement

during the presence of the offshore platform and the fishing (harvesting) restriction in the area.

252